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, 2002
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)
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. [ ]
Indicate by check mark whether the registrant is an
accelerated filer (as defined in Rule 12b-2 of the Act).
YES [X] NO [ ]
As of February 14, 2003, the registrant had 20,860,070
shares of Class A Common Stock outstanding and the aggregate
market value of the voting stock held by nonaffiliates was
approximately $244,242,617. This calculation is based on the
closing price of the shares on the New York Stock Exchange on
February 14, 2003 of $15.60. The registrant also had 898,892
shares of Class B Stock outstanding on February 14, 2003, 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
Page
Items 1
and 2. Business and Properties 3
General 3
Oil Marketing 4
Steaming Operations 5
Electricity Contracts 7
Electricity Generation 8
Impact of Enron Bankruptcy 8
Environmental and Other Regulations 8
Competition 9
Employees 9
Oil and Gas Properties 10
Development 10
Exploration 11
Enhanced Oil Recovery Tax Credits 12
Oil and Gas Reserves 12
Production 12
Acreage and Wells 13
Drilling Activity 13
Title and Insurance 13
Item 3. Legal Proceedings 14
Item 4. Submission of Matters to a Vote of
Security Holders 14
Executive Officers 14
PART II
Item 5. Market for the Registrant's Common Equity
and Related Shareholder Matters 15
Item 6. Selected Financial Data 16
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 17
Item 7A. Quantitative and Qualitative Disclosures
About MarketRisk 21
Item 8. Financial Statements and Supplementary Data 23
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 44
PART III
Item 10. Directors and Executive Officers of the
Registrant 44
Item 11. Executive Compensation 44
Item 12. Security Ownership of Certain Beneficial
Owners and Management 44
Item 13. Certain Relationships and Related Transactions 44
PART IV
Item 14. Controls and Procedures 44
Item 15. Exhibits, Financial Statement Schedules
and Reports on Form 8-K 45
2
PART I
Items 1 and 2. Business and Properties
Company Website
The Company has a website located at www.bry.com. The
website can be used to access recent news releases and Securities
and Exchange Commission filings, crude oil price postings, the
Company's Annual Report and Proxy Statement along with other
items of interest.
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, 2002. 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
principally 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 and staff. 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. Consistent with
this strategy, the Company announced in February 2003 that it has
opened an office in Denver to identify and evaluate potential
opportunities which may achieve the Company's growth goals. From
time to time, the Company also hires consultants or others
knowledgeable in the industry to assist the Company in
identifying, evaluating and acquiring assets. The Company has
approximately $130 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, 2002, the Company's estimated proved
reserves were 101.7 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, 2002 were located in California, with
74%, 20% and 5% of total proved reserves in Kern, Los Angeles and
Ventura Counties, respectively. The Company's reserves have a long
life of approximately 19 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 degrees API gravity and the Montalvo field averages 16 degrees
API gravity). Production in 2002 was 5.3 million BOE, up 4% from
2001 production of 5 million BOE. For the five years 1998 through
2002, the Company's average annual reserve replacement rate was
102% and the acquisition, finding and development cost was $4.12
per BOE.
3
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 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:
2002 2001 2000
Sales of oil and gas 77% 72% 69%
Sales of electricity 22% 26% 31%
Other 1% 2% -%
Oil Marketing
The global and California crude oil markets have remained
volatile due to economic and political forces. The Organization
of Petroleum Exporting Countries (OPEC) has attempted to manage
crude oil prices from petroleum product demand weakness due to
worldwide economic slowdowns and political instability. Product
prices rose in 2002 from the low in mid-January and continued to
exhibit an overall-strengthening trend during the remainder of
the year. Contributing factors to the increase in prices at year-
end included the potential for military conflict in Iraq and the
supply disruptions in Venezuela due to a strike against its
President, Hugo Chavez. Average prices for 2002 were similar to
those in 2001. The NYMEX price for West Texas Intermediate
(WTI), the U.S. benchmark crude oil, averaged $26.15 for 2002
compared to $25.95 for 2001 and $30.26 in 2000. The range for
the year 2002 was broad, however, with a low of $17.97 and a high
of $32.72. The average posted price for the Company's 13 degree
API heavy crude oil was $20.67 for 2002 compared to $18.70 for
2001 and $23.90 for 2000. The range of posted prices for the
Company's heavy crude oil in 2002 included a low of $11.75 and a
high of $26.75.
While crude oil price differentials between WTI and
California's heavy crude widened slightly during the two previous
years, the trend reversed in 2002. The crude price differential
between WTI and California's heavy crude oil has averaged $5.48,
$7.25 and $6.36 for 2002, 2001 and 2000, respectively. A price-
sensitive royalty burdens one of the Company's properties which
produces in excess of 3,000 BPD. The royalty was 75% of the
heavy oil posted price above $14.30 in 2002. This price is
escalated 2% annually.
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. This contract was renegotiated
during 2002 and extended through 2005. Over 90% of the Company's
current production is subject to this new contract. Pricing in
the new agreement is based upon the higher of the average of the
local field posted prices plus a fixed bonus, or WTI minus a
fixed differential. Both methods are calculated using a monthly
determination. In addition to providing a premium above field
postings, the agreement effectively eliminates the Company's
exposure to the risk of widening WTI to California heavy crude
price differentials and allows the Company to effectively hedge
its production based on NYMEX WTI pricing.
4
From time to time, the Company 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. This price protection
program is designed to moderate the effects of a severe price
downturn while allowing Berry to participate in the upside after
a maximum per barrel payment. The hedge can be in the form of a
swap or an option. The Company has utilized bracketed zero-cost
collars as they meet the Company's objectives of retaining
significant upside while being adequately protected on a
significant downside price movement. These price protection
activities resulted in a net cost or (benefit)/Bbl to the Company
of $.72 in 2002, ($.16) in 2001 and $1.31 in 2000.
The following table summarizes the oil hedges in place as of
February 14, 2003:
Crude Oil Hedges
(Based on NYMEX WTI Pricing)
Barrels Floor Ceiling
Term Per Day Sell Put Buy Put Sell Call Buy Call
04/01/2002-03/31/2003 2,500 $ - $20.00 $24.10 $ -
04/01/2002-03/31/2003 2,500 $17.60 $21.60 $25.55 $30.00
01/01/2003-12/31/2003 1,500 $19.00 $23.00 $27.00 $30.85
04/01/2003-03/31/2004 2,500 $18.25 $22.10 $25.40 $30.10
04/01/2003-03/31/2004 2,500 $18.25 $22.10 $25.45 $30.10
04/01/2004-12/31/2004(1) 1,000 $19.00 $22.00 $25.50 $29.40
04/01/2004-12/31/2004(1) 1,000 $19.50 $23.00 $26.00 $29.75
01/01/2004-12/31/2004(1) 1,000 $19.50 $23.00 $26.00 $29.50
01/01/2004-12/31/2004(1) 1,000 $19.50 $23.00 $26.25 $29.85
(1)Hedge was put in place in 2003.
Payments to our counterparties are triggered when NYMEX
monthly average prices are between the Ceiling Sell Call and Buy
Call prices. Conversely, payments from our counterparties are
received when the NYMEX monthly average prices are between the
Floor Sell Put and Buy Put prices. Management regularly monitors
the crude oil markets and the Company's 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, 2002, approximately 94% of the Company's
proved reserves, or 96 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
ownership and efficient operation of cogeneration facilities.
Two of these cogeneration facilities, a 38 megawatt (Mw) and an
18 Mw facility are located on the Company's South Midway-Sunset
field. The Company also owns a 42 Mw cogeneration facility,
consisting of two 21 Mw turbines, which is located at the
Company's Placerita field. Steam generation from these
facilities is more efficient than conventional steam generators,
as both steam and electricity are produced from the cogeneration
facilities. 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, and tested the
market in 2002, the regulation and operating and financial
conditions of the
5
electrical market in California remain in turmoil and are
currently not favorable for these types of investments. The
Company will continue to seek an economic long-term power sales
agreement(s) to support additional cogeneration facilities.
Midway-Sunset Field
For its South Midway-Sunset properties, the Company's steam
production for 2002 was generated by its 38 Mw and 18 Mw
cogeneration facilities (approximately 22,500 barrels of steam
per day (BSPD) including duct-fire, 13,300 in 2001 and 21,000
BSPD in 2000, respectively) 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 for its steam requirements, which
have the capability of generating approximately 3,400 BSPD.
Placerita
On its Placerita properties, the Company generated
approximately 12,750 BSPD in 2002, 8,600 BSPD in 2001 and 12,500
BSPD in 2000 from its 42 Mw cogeneration facility and has the
capability of generating another 11,800 BSPD from conventional
steam generators.
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 increased significantly over HH in
December 2000 by $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. The cost of natural gas purchased
averaged $3.13/Mmbtu, $5.76/Mmbtu and $4.95/Mmbtu in 2002, 2001
and 2000, respectively. The Company operated most of its
conventional steam capacity in 2002 as natural gas prices
moderated to achieve the Company's goal of increasing oil
production to the pre-California electricity crisis levels. In
early 2003, natural gas prices have increased to over $5.00/Mmbtu
and the Company has selectively reduced approximately 6,000 BSPD
from conventional sources to maximize operating margins.
Cogeneration Steam Generation
Going into 2001, the Company had four Standard Offer (SO)
electricity sales contracts related to its three cogeneration
plants. The payments under 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 successfully delivered its power generation in
2002 to paying customers and increased its steam generation
volumes from its cogeneration facilities similar to its pre-2001
historical levels. The Company was also successful in re-
instating three of its Standard Offer Contracts in late 2002 and
began delivering power under these contracts to PG&E and Edison
in January 2003. These contracts should result in improved
electrical pricing for 2003 and are scheduled to terminate no
later than December 31, 2003. Management will pursue extensions
or other long-term contracts at competitive rates for 2004 and
beyond. The $5.37/kwh received on the above fixed electricity
contract will revert to SRAC pricing plus a capacity payment in
July 2006 and the contract will expire in March 2009.
Natural Gas Deliverability
The Company has physical access to gas pipelines, such as
the Kern River 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.
One of the benefits of owning this firm transportation is that it
provides additional flexibility to the Company in securing its
natural gas supply and allows the Company to potentially benefit
from discounted natural gas prices in the Rockies. Another
benefit is that it protects the Company from a potential
recurring situation where SoCal border gas prices are
significantly above Henry Hub pricing. 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, or slightly discounted, to
Henry Hub prices.
Electricity Contracts
The following is a summary of the Company's current
cogeneration electrical contracts and various operational data:
Average Average
Megawatts barrels of
Type Delivered steam
of Contract for sale delivered
Location Contract Purchaser Expiration per hour per day
(1)
2002 2001 2002 2001
Placerita
Placerita I SO2 Edison Mar-2009 18.7 13.4 6,630 5,075
Placerita II RSO1 Edison Q4-2003(2) 15.4 10.1 6,124 3,707
South Midway-Sunset
Cogen 18 RSO1 PG&E Q4-2003(2) 10.7 7.9 6,338 3,570
Cogen 38 RSO1 PG&E Q4-2003(2) 32.2 20.6 16,144 9,723
SO is for "Standard Offer", RSO is for "Reformed or Reinstated
Standard Offer"
(2) Expected expiration
7
Electricity Generation
The total electricity production capacity of the Company's
three cogeneration facilities is 98 Mw. Each facility is
centrally located on an oil producing property such that the
steam generated by the facility is capable of being delivered to
the wells that require the steam for the enhanced oil recovery
process. 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.
On August 22, 2002, the California Public Utilities
Commission mandated that investor owned utilities offer Standard
Offer contracts to certain qualified facilities. The Company met
these requirements and has entered into Revised Standard Offer
(RSO1) contracts with Southern California Edison Company and
Pacific Gas and Electric Company effective January 2003. These
contracts should result in improved electrical pricing, which in
turn will contribute to lower operating costs for the Company's
crude oil production operations. These contracts will expire no
later than December 31, 2003. Management will pursue extensions
or other longer-term contracts at competitive rates for 2004 and
beyond.
To protect a portion of the Company's electrical production
from low off-peak power prices, the Company entered into fixed
price sale (swap) agreements. These price protection activities
resulted in a net cost/Mwh to the Company of $.38 in 2002.
Following are the contracts currently in effect:
Electricity Hedges
Based on Dow Jones SP15 Index
1/1/03-3/31/03 30 MWH per off-peak hour $ 22.50
4/1/03-5/31/03 30 MWH per off-peak hour $ 21.00
These contracts are financial instruments and are independent of
the RSO1 physical contracts.
Impact of Enron Bankruptcy
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 in the Enron bankruptcy proceedings. 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 these areas
relate to the Company's operations. The Company strives to
achieve the long-term goal of sustainable development within the
framework of sound environmental, health and safety practices and
standards. 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.
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.
8
Therefore, Berry has programs in place to identify and
manage known risks, to train employees in the proper performance
of their duties and to incorporate viable new technologies into
our operations. 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 lower emissions from stationary sources.
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 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,
2002 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 and 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, 2002, the Company had 113 full-time
employees, up from 110 full-time employees at December 31, 2001.
9
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 75% of the Company's proved oil and gas reserves
and approximately 70% 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
enhanced oil recovery (EOR) methods, primarily cyclic steaming.
During 2002, 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 58 wells drilled in this field in
2002, 19 were drilled on the Formax properties, and 16 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 2003, the Company plans
to drill an additional 67 wells in this field, including 27 on
the Formax properties and 13 horizontals.
In the northern part of the Midway-Sunset field, our 2003
development plans call for the drilling of ten new wells and
eight workovers to implement two steam drive pilots in a sizable
diatomite accumulation. This 2003 program follows an encouraging
corehole that the Company drilled in 2002, indicating both good
oil saturation and rock properties. Ultimate completion of this
program is dependent on the results of the 2003 pilots.
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 recovery methods, primarily steam
flooding.
During 2002, the Company drilled eight development wells at
Placerita to install Phase One of a major development campaign at
the north end of the field. Included in the Company's 2003
development plan is the continuation of the north end development
with ten steamflood producers and six major workovers.
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 5% of Berry's daily
production. The wells produce from an average depth of
approximately 11,500 feet. No new wells were drilled in 2002,
however three successful major workovers were done. There are no
plans at this time to drill any new wells in 2003, however two
idle wells are scheduled to be returned to production.
South Joe Creek - In April 2001, Berry purchased a 15.83%
non-operated working interest in the South Joe Creek coalbed
methane field which represented interests in federal, state and
local leases totaling approximately 5,800 acres in the Campbell
County portion of the Powder River Basin in Wyoming. The
property has 85 wells (13 net). Six additional wells (1 net)
were drilled in 2002 and another 18 wells (3 net) are planned
for drilling and completion in 2003. At year-end, the
production rate was 15 million cubic feet of gas (2.4 net)
per day.
Kansas and Illinois Coalbed Methane (CBM) Projects - In mid-
2002, the Company began to build a significant acreage position
in both Eastern Kansas (208,000 acres) and Central Illinois
(54,000 acres) to develop gas production and reserves from known
coalbeds (the leased acreage indicated is as of February 14,
2003). The Company drilled a five-spot production pilot in each
state late in 2002 and both are currently in the early dewatering
stage. As such, the Company has no recorded reserves in either
state at December 31, 2002. The Company is currently evaluating
the location and method of drilling additional test wells in
Kansas.
10
The following is a summary of the Company's capital
expenditures incurred during 2002 and 2001 and projected capital
expenditures for 2003. It should be noted that the Company had
projected 2002 capital expenditures of $19.6 million. The
capital expenditure budget for 2002 was significantly revised
upward as oil prices rose.
CAPITAL EXPENDITURES SUMMARY
(in thousands)
2003(1) 2002 2001
(Projected)
Midway-Sunset Field
New wells $ 12,160 $ 10,224 $ 4,799
Remedials/workovers 1,365 1,981 1,367
Facilities 4,050 2,238 4,069
------- ------- -------
17,575 14,443 10,235
------- ------- -------
Placerita
New wells 5,000 5,278 782
Remedials/workovers 545 174 465
Facilities 1,180 6,862 1,660
------- ------- -------
6,725 12,314 2,907
------- ------- -------
Montalvo
Remedials/workovers 450 909 674
Facilities 590 179 331
------- ------- -------
1,040 1,088 1,005
------- ------- -------
South Joe Creek (2)
New wells 396 355 593
Facilities 50 216 79
------- ------- -------
446 571 672
------- ------- -------
Kansas and Illinois(CBM)(3)
New wells 780 1,185 -
Facilities 555 47 -
------- ------- -------
1,335 1,232 -
------- ------- -------
Other 499 984 76
------- ------- -------
Totals $ 27,620 $ 30,632 $ 14,895
======= ======= =======
(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.
(3) Represents coalbed methane (CBM) development activity.
Exploration
The Company considers its pilot wells in both Kansas and
Illinois to be exploratory in nature as there is not proven
production near those areas. However, these are relatively
inexpensive shallow wells. 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.
11
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, 2002. 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, 2002. For the
Company's operated properties, these reserve estimates are filed
annually with the U.S. Department of Energy. See 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:
2002 2001 2000
Net annual production:(1)
Oil (Mbbls) 5,123 4,996 5,434
Gas (Mmcf) 769 288 199
Total equivalent barrels(2) 5,251 5,044 5,467
Average sales price:
Oil (per Bbl) $ 19.54 $ 19.70 $ 21.70
Gas (per mcf) 2.22 5.09 4.34
Per BOE 19.39 19.79 21.72
Average operating cost - oil
and gas production (per BOE)(3) 8.49 7.99 8.20
(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 $1.72, $1.31 and $0.53 for
2002, 2001 and 2000, respectively. See Note 2 to the financial
statements.
12
Acreage and Wells
At December 31, 2002, the Company's properties accounted for
the following developed and undeveloped acres:
Developed Acres Undeveloped Acres Total
Gross Net Gross Net Gross Net
California 7,226 7,226 7,244 7,244 14,470 14,470
Kansas - - 190,645 190,645 190,645 190,645
Illinois - - 52,138 52,138 52,138 52,138
Other 3,720 573 1,746 277 5,466 850
------ ------ ------- ------- ------- -------
10,946 7,799 251,773 250,304 262,719 258,103
====== ====== ======= ======= ======= =======
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 2,520 gross oil wells (2,498 net) and
104 gross gas wells (25 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:
2002 2001 2000
Gross Net Gross Net Gross Net
Exploratory wells
drilled:
Productive(in testing) 11 11 - - - -
Dry(1) - - - - - -
Development wells
drilled:(2)
Productive 81 76 103 47 81 81
Dry(1) - - 1 - - -
Total wells
drilled:
Productive 92 87 103 47 81 81
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 include 6 wells gross, 1 well net for 2002
and 67 wells gross, 11 wells net for 2001 that were drilled
at South Joe Creek which the Company holds a 15.83% working
interest.
On December 31, 2002, there were no wells being drilled by
the Company. The 2003 drilling activity commenced in February
2003.
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.
13
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, 2002)
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, 53, 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, 46, 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, 42, 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, a subsidiary of Atlantic Richfield Corp.
(ARCO). 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, 36, joined the Company effective February
1, 2002 as the Vice President of Corporate Development. Mr.
Duginski has a mechanical engineering background and was
previously with Texaco, Inc. from 1988 to 2002 where he was most
recently responsible for new business development and gas and
power operations.
BRIAN L. REHKOPF, 55, 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 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, 56, has been Controller since December 1985.
KENNETH A. OLSON, 47, has been Corporate Secretary since
December 1985 and Treasurer since August 1988.
14
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
authorized the purchase of 100,000 shares of Berry Petroleum
Company Class A Common Stock until November 8, 2003 at $14.06 per
share. The Warrant was purchased from the holders in 2002 and
was subsequently canceled.
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 2002 and 2001
are shown below:
2002 2001
Dividends Dividends
Price Range Per Price Range per
High Low Share High Low Share
First Quarter $ 16.90 $ 13.25 $.10 $ 14.75 $ 12.05 $.10
Second Quarter 17.58 15.45 .10 15.05 11.00 .10
Third Quarter 18.25 14.52 .10 16.99 13.65 .10
Fourth Quarter 17.50 15.60 .10 17.75 14.26 .10
The closing price per share of Berry's Common Stock, as
reported on the New York Stock Exchange Composite Transaction
Reporting System for February 14, 2003, December 31, 2002 and
December 31, 2001 was $15.60, $17.05 and $15.70, respectively.
The number of holders of record of the Company's Common
Stock was 725 (and approximately 3,600 street name shareholders)
as of February 14, 2003. There was one Class B Stockholder of
record as of February 14, 2003.
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. No additional shares were repurchased
in 2002.
Since Berry Petroleum Company's formation in 1985 through
December 31, 2002, the Company has paid dividends on its Common
Stock for 53 consecutive quarters and previous to that for eight
consecutive semi-annual periods. 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, 2002, 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.
15
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, 2002 were derived from the audited
financial statements and the accompanying notes to those
financial statements (in thousands, except per share, per BOE and
% data):
2002 2001 2000 1999 1998
Statement of Operations Data:
Sales of oil and gas $ 102,026 $ 100,146 $ 118,801 $ 66,615 $ 39,858
Sales of electricity 28,827 35,917 52,765 33,731 15,680
Operating costs - oil and
gas production 44,604 40,281 44,837 27,829 18,272
Operating costs -
electricity generation 28,496 35,506 50,566 27,930 15,236
General and administrative
expenses (G&A) 7,928 7,174 7,754 6,269 3,975
Depreciation, depletion &
amortization (DD&A) 16,452 16,520 14,030 12,294 10,080
Net income 30,024 21,938 37,183 18,006 3,879
Basic net income per share 1.38 1.00 1.69 .82 .18
Weighted average number of
shares outstanding 21,741 21,973 22,029 22,010 22,007
Balance Sheet Data:
Working capital $ (3,689)$ 5,837 $ (1,154)$ 8,435 $ 9,081
Total assets 258,073 237,973 238,359 207,649 173,804
Long-term debt 15,000 25,000 25,000 52,000 30,000
Shareholders' equity 172,058 153,153 145,224 116,213 106,924
Cash dividends per share .40 .40 .40 .40 .40
Operating Data:
Cash flow from operations 57,895 35,433 65,934 24,809 19,924
Capital expenditures
(excluding acquisitions) 30,632 14,895 25,253 9,122 6,981
Property/facility
acquisitions 5,880 2,273 3,182 33,605 2,991
Oil and gas producing
operations (per BOE):
Average sales price $ 19.39 $ 19.79 $ 21.72 $ 13.07 $ 9.05
Average operating costs(1) 8.49 7.99 8.20 5.47 4.15
G&A 1.51 1.42 1.42 1.23 .90
------- ------- ------- ------- -------
Cash flow 9.39 10.38 12.10 6.37 4.00
DD&A 3.13 3.28 2.57 2.42 2.29
------- ------- ------- ------- -------
Operating income less G&A $ 6.26 $ 7.10 $ 9.53 $ 3.95 $ 1.71
======= ======= ======= ======= =======
Production (BOE) 5,251 5,044 5,467 5,090 4,399
Production (Mwh) 748 483 764 728 448
Proved Reserves Information:
Total BOE 101,719 102,855 107,361 112,541 92,609
Present value (PV10) of
estimated future cash flow
before income taxes $602,157 $356,556 $721,770 $714,555 $113,811
Year-end average BOE price
for PV10 purposes 24.91 14.13 21.13 19.37 7.09
Other:
Return on average
shareholders' equity 18.5% 14.7% 28.5% 16.5% 3.5%
Return on average total
assets 12.5% 8.7% 16.8% 9.0% 2.2%
Total debt/total debt plus
equity 8.0% 14.0% 14.7% 30.9% 21.9%
Year-end stock price $ 17.05 $ 15.70 $ 13.375 $ 15.125 $ 14.188
Year-end market
capitalization $370,865 $341,192 $294,699 $332,920 $312,247
(1) Including monthly
expenses in excess of $ 1.72 $ 1.31 $ 0.53 $ - $ 0.14
monthly revenues from
cogeneration operations
16
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,
2002, 2001and 2000 and the financial condition, liquidity and
capital resources as of December 31, 2002 and 2001. 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 $30 million, or $1.38 per share, in 2002
on revenues of $132.5 million, up 37% from $21.9 million, or
$1.00 per share, on revenues of $138.5 million in 2001, but were
19% lower than $37.2 million, or $1.69 per share, on revenues of
$172.0 million earned in 2000, Berry's most profitable year. The
increase in income in 2002 versus 2001 was due to higher
production, lower interest expense and the recovery of $3.6
million, which represented a portion of electricity receivables
written off in 2001, partially offset by higher operating costs.
The following table presents certain operating data for the
years ended December 31:
2002 2001 2000
Oil and Gas
Net production - BOE/D 14,387 13,820 14,937
Per BOE:
Average sales price $19.39 $19.79 $21.72
Operating costs(1) 7.94 7.50 7.77
Production taxes .55 .49 .43
Total operating costs 8.49 7.99 8.20
DD&A 3.13 3.28 2.57
G&A 1.51 1.42 1.42
Interest expense .20 .74 .58
Electricity
Electric power produced -
Megawatt (Mw) hrs/day 2,050 1,325 2,088
Electric power sold -
Megawatt (Mw) hrs/day 1,848 1,245 1,979
Average sales price/Mw $40.06 $79.14 $72.26
Fuel gas cost/Mmbtu 3.13 5.76 4.95
(1) Including monthly expenses in excess of monthly revenues from
cogeneration operations of $1.72, $1.31 and $.53 in 2002, 2001 and
2000, respectively.
BOE/D = Barrels of oil equivalent per day
Operating income from oil and gas operations was $41.3
million in 2002, down from $42.2 million in 2001, and $60.3
million in 2000. The decrease from 2001 was due primarily to
higher operating costs, partially offset by higher production.
17
Oil and gas production (BOE/D) for 2002 was 14,387, 4%
higher than 13,820 in 2001, but 4% lower than 14,937 in 2000.
Production volumes declined dramatically in 2001, reaching a low
of approximately 12,800 BOE/D in mid-2001 due to the curtailment
of steaming operations early in 2001 as a result of the
California electricity crisis. Steaming operations were re-
established by August of 2001 and the Company exited 2001 with a
production level of approximately 13,500 BOE/D. Steam injection
rates of 54,000 to 64,000 barrels of steam per day were
maintained for all of 2002. This effort combined with the
effects of the 2002 drilling program resulted in production rate
improvement throughout the year with an exit rate of
approximately 15,700 barrels per day for December 2002. The
Company plans to continue with significant drilling and
development projects in 2003 with a goal of averaging 16,400
BOE/D in 2003 and exiting this year at 17,700 BOE/D.
The 2002 average sales price/BOE for the Company's crude oil
was $19.39, down 2% from $19.79 in 2001 and 10% from $21.72 in
2000. Posted oil prices for the Company's 13 degree heavy crude
oil began the year at $13.08 and escalated steadily to $25.50 at
December 31, 2002 and have escalated further since year-end to a
price of $30.75 on February 14, 2003. Over 90% of the Company's
crude oil has been contracted with a single customer until
December 31, 2005 and is sold at prices based upon the higher of
the average local field posted prices plus a fixed bonus, or WTI
minus a fixed differential.
From time to time, the Company 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. This price protection
program is designed to moderate the effects of a severe price
downturn while allowing Berry to participate in the upside after
a maximum per barrel payment. The hedge can be in the form of a
swap or an option. The Company has utilized bracketed zero-cost
collars as they meet the Company's objectives of retaining
significant upside while being adequately protected on a
significant downside price movement. Additionally, the Company
utilizes more than one counterparty on its hedges and monitors
each counterparty's credit rating. The Company's current hedging
program is designed to hedge approximately 40% to 45% of its net
production while retaining some upside on the hedged barrels in
the event of a major price increase. These price protection
activities resulted in a net cost (benefit)/Bbl to the Company of
$.72, ($.16) and $1.31 in 2002, 2001 and 2000, respectively.
Electricity prices relative to the cost of natural gas to
generate such electricity in 2002 were very weak for the entire
year. The Company produced approximately 67% of its power for
sale on the open market and received an average of $26.95/Mwh for
that portion of total electricity sales and $40.06 per Mwh
overall. In January 2003, Berry began delivery of electricity
under three reformed or reinstated Standard Offer contracts with
Pacific Gas and Electric Company and Southern California Edison
Company, which should result in improved electrical pricing and
contribute to lower operating costs for the Company's crude oil
production operations during 2003. These contracts are scheduled
to terminate no later than December 31, 2003. Management will
pursue extensions or other longer-term contracts at competitive
rates for 2004 and beyond. Berry's fourth contract, which is
based on a fixed electricity sales price until July 31, 2006 and
then a short-run avoided cost formula, expires in March 2009.
To protect a portion of the Company's electrical production
from low off-peak power prices, the Company entered into fixed
price sale (swap) agreements on 30 Mw of off-peak power from
October 2002 through May of 2003 at prices ranging from $21.00 to
$22.50 /Mwh.
Operating costs in 2002 were $44.6 million, or $8.49 per
BOE, up from $40.3 million in 2001, or $7.99 per BOE and
comparable to $44.8 million in 2000, or $8.20 per BOE. The
primary reason for the increase from 2001 was higher steam costs.
Steam costs increased due to higher volumes of steam from
conventional generators, weak electricity prices at the Company's
cogeneration facilities and the suspension of steaming for a
portion of 2001. In addition to higher steam costs, well work
increased by $.8 million in 2002 due to the higher steaming
activity and increased efforts to bring more marginal producers
on line to capture revenue from improving oil prices. In early
2003, natural gas prices increased to over $5.00/Mmbtu and the
Company has selectively reduced steam injection approximately
6,000 BSPD. Management anticipates that operating costs will
increase to an average of approximately $8.50 to $9.50 per BOE
for 2003.
DD&A in 2002 was $16.5 million, or $3.13 per BOE, equivalent
to $16.5 million, or $3.28 per BOE in 2001, but higher than $14.0
million, or $2.57 per BOE, in 2000. The increase from 2000 was
primarily related to a higher asset base due to the cumulative
effect of development activity in recent years. The Company is
projecting DD&A in 2003, on a BOE basis, to be approximately
$3.00 to $3.10 per BOE.
18
G&A expenses in 2002 were $7.9 million, or $1.51 per BOE, up
6% and 1% from $7.2 million, or $1.42 per BOE, in 2001 and $7.8
million, or $1.42 per BOE, in 2000. The increase from 2001 was
primarily related to higher costs to evaluate potential
acquisitions and rental and other costs associated with the
Company's Bakersfield headquarters office. The Company is
targeting G&A of approximately $1.50 per BOE in 2003.
Interest expense in 2002 decreased to $1.0 million, or $.20
per BOE, from $3.7 million, or $.74 per BOE, in 2001. Early in
2001, the Company drew down its line of credit to compensate for
large unpaid receivables from electricity sales in late 2000 and
early 2001. Later in 2001 and early in 2002, most of the
receivables were recovered and long-term debt was reduced from a
peak of $70 million to $25 million at December 31, 2001. Long-
term debt was further reduced in 2002 through internally
generated funds to a balance of $15 million at December 31, 2002.
The Company experienced an effective tax rate of 20% in
2002, up slightly from the 19% reported in 2001, but down from
28% reported in 2000. The low 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 fifth
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 well
below the statutory rate in 2003.
In 2002, Berry adopted SFAS No. 143, `Accounting for Asset
Retirement Obligations.' The Company has recorded the estimate
costs for the ultimate abandonment of its wells and facilities
for many years under SFAS No. 19 and the effect of the change on
2002 net income was immaterial. The effect on net income in 2003
under the newly adopted method will be a pre-tax charge of
approximately $.5 million compared to a pre-tax charge of
approximately $.8 million under the previous method. The most
significant effect of the change was to move the current
accumulated financial obligation to a long-term liability
account. The value of this obligation under our previous method
had been recorded as a reduction to the total book value of the
Company's property, plant and equipment. The accrued abandonment
obligation at December 31, 2002 was $4.6 million. The recorded
abandonment obligation at December 31, 2001 under the previous
method of $5.4 million was reclassified to a long-term liability
in the current year presentation for comparability purposes.
Financial Condition, Liquidity and Capital Resources
Working capital at December 31, 2002 was negative ($3.7)
million, down from $5.8 million at December 31, 2001 and negative
($1.2) million at December 31, 2000. Net cash provided by
operations in 2002 was $57.9 million, up 64% from $35.4 million
in 2001, but 14% lower than $65.9 million in 2000. Cash
generated was used to fund $30.6 million in capital expenditures,
$5.9 million in leasehold acquisitions, pay dividends of $8.7
million and reduce long-term debt by $10 million.
Total capital expenditures incurred excluding acquisitions
in 2002 were $30.6 million, up 105% from $14.9 million in 2001.
Included in this year's projects was the drilling of 87 wells, 16
of which were horizontal and the completion of 69 workovers. The
Company also made facility improvements totaling $9.6 million on
its producing assets. These projects were responsible for a
large portion of the production gains made in 2002 and should
continue to contribute to production increases in 2003 and
beyond.
The Company also acquired acreage in Kansas and Illinois in
2002 for the purpose of exploring for economic concentrations of
coalbed methane. At December 31, 2002, approximately 191,000
acres in Kansas and 52,000 acres in Illinois were leased at a
cost of approximately $5.9 million. In 2002, the Company drilled
4 producing and one water disposal well and one well was returned
to production on a pilot in Illinois and 5 producing wells and 1
water disposal well were drilled in another pilot in Kansas.
Additional wells may be completed in Kansas in 2003. The
evaluation of these projects is expected to continue through
most of 2003.
The Company has continued to maintain its $150 million
revolving bank facility with approximately $130 million
available for potential acquisitions or other purposes at
December 31, 2002.
The Company has budgeted $27.6 million, excluding property
acquisitions, in capital projects for 2003. This program, on a
net well basis, consists of 101 net vertical wells, 13 horizontal
producers and 49 workovers. In addition to drilling and workover
activities, $6.4 million in facilities are scheduled for
completion on the Company's core properties. One of the focuses
of the 2003 budget is to continue to develop the proved but
undeveloped reserves from the Company's Placerita properties.
19
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. In 2002, there
were no additional shares repurchased under this program,
however, the Company did purchase and cancel an outstanding
warrant for 100,000 shares.
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
2002.
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 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 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 remediation can be determined,
the applicable amount is accrued. Actual costs can differ from
estimates due to changes in laws and regulations, discovery and
analysis of site conditions and changes in technology.
The Company makes certain estimates for income taxes, 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
of its oil and gas properties and equipment. The Company reviews
its estimate of the future obligation periodically and accrued
the estimated obligation monthly based on SFAS No. 19, prior to
adoption of SFAS No. 143, as described in `Recent Accounting
Developments' below. The implementation of this standard had an
immaterial impact on the financial statements of the Company.
Recent Accounting Developments
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. However, as allowed, the Company opted
to implement this standard in 2002. See Note 13 to the Financial
Statements.
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
20
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 were effective in the first
quarter of 2002 and its implementation had no material impact on
the financial statements taken as a whole.
In the fourth quarter of 2002, the Company adopted the
supplemental disclosure requirements of SFAS No. 148, "Accounting
for Stock-Based Compensation - Transition and Disclosure", which
amended SFAS No. 123, "Accounting for Stock-Based Compensation."
The Company continues to record compensation related to employee
stock options based on the intrinsic value method per APB Opinion
No. 25, "Accounting for Stock Issued to Employees." SFAS No. 148
encourages companies to voluntarily elect to record the
compensation based on market value either prospectively, as
defined in SFAS No. 123, or retroactively or in a modified
prospective method. Among other things, the Company is concerned
about the reasonableness of the values of its stock options
determined using the Black Scholes method. Therefore, the
Company has delayed the potential transition to recording stock
compensation based on fair market value until there is more
clarity regarding the measurement of stock option values.
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.
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 approximate $5.7 million change in
annual revenues. The Company periodically enters into hedge
contracts to manage the oil price risk. In 2002, the Company
entered into a number of hedges, based on WTI pricing, on 6,500
barrels per day, or approximately 42% of total production. The
hedges have a floor ranging from $21.60 to $23.00, whereby the
Company will receive $3.85 to $4.00 below these prices. They
also have ceilings ranging from $24.10 to $27.00, whereby the
Company will give up $3.85 to $4.70 above these prices.
Additionally, the Company utilizes more than one counterparty on
these hedges and monitors each counterparty's credit rating.
The Company is also at risk for a widening of the
differential between the WTI crude oil price and the posted price
of the Company's heavy crude oil. To minimize this risk, the
Company has a sales contract in place through 2005 where more
than 90% of its crude oil production is priced at the higher of
local field posting plus a bonus, or WTI minus a fixed
differential.
The Company also has market risk exposure related to the
price received for the sale of its electricity production and the
cost paid by the Company for the natural gas used in its
cogeneration operations. The Company's three cogeneration
facilities, when combined, have electricity production capacity
of 98 Mw of electricity/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). 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
used in the cogeneration facilities equates to a change of
approximately $1.0 million in operating costs. The Company has a
long-term electricity sales contract in place through July 31, 2006
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.
During 2002, the majority of the remaining electricity was sold
on the open market to a creditworthy customer. To protect a
portion of the Company's electrical production from low off-peak
power prices, the Company entered into a series of fixed price
(swap) agreements on 30 Mwh of off-peak hour electricity. At
December 31, 2002, the Company has swap agreements in place
through May 31, 2003 at prices ranging from $21.00 to $22.50 per
Mwh. In January 2003, the Company entered into three reformed
or reinstated Standard Offer contracts with PG&E and SCE which
should result in improved electrical pricing in 2003. These
contracts will expire no later than December 31, 2003. The
Company is pursuing longer-term arrangements on the sale of
electricity and may enter into hedges on its natural gas
purchases to seek to improve the spark spread in 2003 and beyond.
21
The Company also consumes up to an additional 10,000
Mmbtu/day of additional natural gas as fuel in its conventional
generators, which are used to supplement the Company's steam
requirements. A change of $.10 in the cost of this natural gas
requirement equates to a change of approximately $.4 million in
operating costs. The Company may enter into hedges on natural
gas purchases to help control this cost or shut-in the
conventional generators if deemed appropriate.
Related to its natural gas purchases, the Company is also
exposed to the volatility in the differential between gas prices
at the Southern California border and Henry Hub delivery points.
To help minimize the risk, the Company entered into a 12,000
Mmbtu/day firm transportation agreement on the Kern River
pipeline expansion with gas deliveries to commence in mid-2003.
This agreement provides the Company additional flexibility in
securing its natural gas supply and allows the Company to
potentially benefit from discounted natural gas prices in the
Rockies. This is a take-or-pay contract and the Company is
required to pay approximately $.71/Mmbtu if the Company does not
take delivery of gas volumes under the agreement.
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, a
limited marketplace for electricity sales within California,
counterparty risk, competition, environmental risks, litigation
uncertainties, drilling, development and operating risks, the
availability of drilling rigs and other support services,
legislative and/or judicial decisions and other government
regulations.
22
Item 8. Financial Statements and Supplementary Data
BERRY PETROLEUM COMPANY
Index to Financial Statements and
Supplementary Data
Page
Report of PricewaterhouseCoopers LLP, Independent
Accountants 24
Balance Sheets at December 31, 2002 and 2001 25
Statements of Income for the
Years Ended December 31, 2002, 2001 and 2000 26
Statements of Comprehensive Income for the
Years Ended December 31, 2002, 2001 and 2000 26
Statements of Shareholders' Equity for the
Years Ended December 31, 2002, 2001 and 2000 27
Statements of Cash Flows for the
Years Ended December 31, 2002, 2001 and 2000 28
Notes to the Financial Statements 29
Supplemental Information About Oil & Gas
Producing Activities 42
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.
23
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, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2002 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/s PricewaterhouseCoopers LLP
Los Angeles, California
February 12, 2003
24
BERRY PETROLEUM COMPANY
Balance Sheets
December 31, 2002 and 2001
(In Thousands, Except Share Information)
2002 2001
ASSETS
Current assets:
Cash and cash equivalents $ 9,866 $ 7,238
Short-term investments available for sale 660 594
Accounts receivable 15,582 17,577
Prepaid expenses and other 2,597 2,792
-------- --------
Total current assets 28,705 28,201
Oil and gas properties (successful efforts
basis), buildings and equipment, net 228,475 208,860
Other assets 893 912
-------- --------
$ 258,073 $ 237,973
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 19,189 $ 11,197
Accrued liabilities 6,470 7,089
Federal and state income taxes payable 2,612 4,078
Fair value of derivatives 4,123 -
-------- --------
Total current liabilities 32,394 22,364
Long term liabilities:
Deferred income taxes 33,866 32,009
Long-term debt 15,000 25,000
Abandonment obligation 4,596 5,447
Fair value of derivatives 159 -
-------- --------
53,621 62,456
Commitments and contingencies (Notes 9 and 10) - -
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;
20,852,695 shares issued and outstanding 209 208
(20,833,094 in 2001)
Class B Stock, 1,500,000 shares authorized;
898,892 shares issued and outstanding 9 9
(liquidation preference of $899)
Capital in excess of par value 49,052 48,905
Accumulated other comprehensive loss (2,569) -
Retained earnings 125,357 104,031
-------- --------
Total shareholders' equity 172,058 153,153
-------- --------
$ 258,073 $ 237,973
======== ========
The accompanying notes are an integral part of these financial
statements.
25
BERRY PETROLEUM COMPANY
Statements of Income
Years ended December 31, 2002, 2001 and 2000
(In Thousands, Except Per Share Data)
2002 2001 2000
Revenues:
Sales of oil and gas $ 102,026 $ 100,146 $ 118,801
Sales of electricity 28,827 35,917 52,765
Interest and dividend income 536 2,150 447
Other income 1,116 328 36
-------- -------- --------
132,505 138,541 172,049
Expenses: -------- -------- --------
Operating costs - oil and gas
production 44,604 40,281 44,837
Operating costs - electricity
generation 28,496 35,506 50,566
Depreciation, depletion &
amortization 16,452 16,520 14,030
General and administrative 7,928 7,174 7,754
Interest 1,042 3,719 3,186
(Recovery) write-off of
electricity receivable (3,631) 6,645 -
Loss on termination of derivative
contracts - 1,458 -
-------- -------- --------
94,891 111,303 120,373
-------- -------- --------
Income before income taxes 37,614 27,238 51,676
Provision for income taxes 7,590 5,300 14,493
-------- -------- --------
Net income $ 30,024 $ 21,938 $ 37,183
======== ======== ========
Basic net income per share $ 1.38 $ 1.00 $ 1.69
======== ======== ========
Diluted net income per share $ 1.37 $ .99 $ 1.67
======== ======== ========
Weighted average number of
shares of capital stock
outstanding (used to calculate
basic net income per share) 21,741 21,973 22,029
Effect of dilutive securities:
Stock options 156 113 185
Other 42 24 26
-------- -------- --------
Weighted average number of
shares of capital stock used
to calculate diluted net
income per share 21,939 22,110 22,240
======== ======== ========
Statements of Comprehensive Income
Years Ended December 31, 2002, 2001 and 2000
(In Thousands)
2002 2001 2000
Net income $ 30,024 $ 21,938 $ 37,183
Unrealized gains (losses) on
derivatives, net of income
taxes of $1,713, $0 and $294,
respectively (2,569) - 441
Reclassification of unrealized
gains included in net income - (441) -
-------- -------- --------
Comprehensive income $ 27,455 $ 21,497 $ 37,624
======== ======== ========
The accompanying notes are an integral part of these financial
statements.
26
BERRY PETROLEUM COMPANY
Statements of Shareholders' Equity
Years Ended December 31, 2002, 2001 and 2000
(In Thousands, Except Per Share Data)
Accumulated
Capital Other
in Comprehen-
Excess sive
of Par Retained Income Shareholders'
Class A Class B Value Earnings (loss) Equity
Balances at January
1, 2000 $ 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)
Unrealized losses on
derivatives - - - - (441) (441)
Net income - - - 21,938 - 21,938
----- ----- ------- ------- ----- --------
Balances at December
31, 2001 208 9 48,905 104,031 - 153,153
Stock options exercised 1 - 57 - - 58
Deferred director fees
stock compensation - - 190 - - 190
Retirement of warrants - - (100) - - (100)
Cash dividends declared-
$.40 per share - - - (8,698) - (8,698)
Unrealized losses on
derivatives - - - - (2,569) (2,569)
Net income - - - 30,024 - 30,024
----- ----- ------- ------- ----- --------
Balances at December
31, 2002 $ 209 $ 9 $ 49,052 $125,357 $(2,569) $ 172,058
===== ===== ======= ======= ===== ========
The accompanying notes are an integral part of these financial
statements.
27
BERRY PETROLEUM COMPANY
Statements of Cash Flows
Years Ended December 31, 2002, 2001 and 2000
(In Thousands)
2002 2001 2000
Cash flows from operating activities:
Net income $ 30,024 $ 21,938 $ 37,183
Depreciation, depletion and amortization 16,452 16,520 14,030
Increase (decrease) in deferred income
tax liability 1,857 (50) 3,147
Other, net (184) (505) 249
------- ------- -------
Net working capital provided by
operating activities 48,149 37,903 54,609
Decrease (increase) in current assets
other than cash, cash equivalents
and short-term investments 3,839 11,241 (14,227)
Increase (decrease) in current
liabilities other than notes payable 5,907 (13,711) 25,552
------- ------- -------
Net cash provided by operating activities 57,895 35,433 65,934
------- ------- -------
Cash flows from investing activities:
Capital expenditures, excluding property
acquisitions (30,632) (14,895) (25,253)
Property acquisitions (5,880) (2,273) (3,182)
Purchase of short-term investments (660) (1,183) (584)
Maturities of short-term investments 594 1,171 600
Other, net 52 151 49
------- ------- -------
Net cash used in investing activities (36,526) (17,029) (28,370)
------- ------- -------
Cash flows from financing activities:
Proceeds from issuance of long-term debt 5,000 45,000 1,000
Payment of long-term debt (15,000) (45,000) (28,000)
Dividends paid (8,698) (8,784) (8,812)
Share repurchase program - (5,112) -
Other, net (43) (1) (1)
------- ------- -------
Net cash used in financing activities (18,741) (13,897) (35,813)
------- ------- -------
Net increase in cash and cash equivalents 2,628 4,507 1,751
Cash and cash equivalents at beginning of
year 7,238 2,731 980
------- ------- -------
Cash and cash equivalents at end of year $ 9,866 $ 7,238 $ 2,731
======= ======= =======
Supplemental disclosures of cash flow
information:
Interest paid $ 1,321 $ 3,532 $ 2,999
======= ======= =======
Income taxes paid $ 5,420 $ 5,635 $ 9,712
======= ======= =======
Supplemental non-cash activity:
Decrease in fair value of derivatives:
Current (net of income taxes of $1,649) $ 2,474 $ - $ -
Non-current (net of income taxes of $63) 95 - -
------- ------- -------
Net decrease to accumulated other
comprehensive income $ 2,569 $ - $ -
======= ======= =======
The accompanying notes are an integral part of these financial
statements.
28
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 97% of the Company's production is heavy crude oil,
which is principally sold to a refiner. The Company has invested
in cogeneration facilities which provide steam required for the
extraction of heavy oil and which generate 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. In
certain cases, such as coalbed methane exploration plays, the
drilling costs may be capitalized for up to a year before it is
known whether proved economic reserves have been discovered. At
that point, if unsuccessful, the costs will be expensed as
exploratory dry hole costs.
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. 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. The estimated costs of plugging and
abandoning wells and related facilities were accrued using the
units-of-production method and were considered in determining
DD&A expense. However, in 2002 the Company adopted SFAS No. 143,
"Accounting for Asset Retirement Obligations." Under this
standard, the Company records the fair value of the future
abandonment as capitalized abandonment costs with an offsetting
abandonment liability. The capitalized abandonment costs are
amortized using the units-of-production method. The Company
increases the liability monthly by recording accretion expense
using the Company's credit adjusted interest rate. 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.
29
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
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. Any
liabilities arising hereunder 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" or "Operating costs - electricity
generation, as applicable." Natural gas transportation costs
included in these catergories were $1.4 million, $1.2 million and
$1.6 million for 2002, 2001 and 2000, respectively.
30
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
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 plan. The supplemental disclosure
requirements of SFAS No. 123, as amended in SFAS No. 148,
"Accounting for Stock-Based Compensation - Transaction and
Disclosure," related to the Company's stock option plan is
presented below:
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:
2002 2001 2000
Yield 2.55% 2.72% 2.77%
Expected option life - years 7.5 7.5 4.5
Volatility 33.45% 38.71% 36.53%
Risk-free interest rate 4.09% 4.65% 4.85%
Had compensation cost for the Company's stock based
compensation plan (see Note 11) been based upon the fair value at
the grant dates for awards under the plan consistent with the
method of SFAS No. 123, the Company's compensation cost, net of
related tax effects, net income and earnings per share would have
been recorded as the proforma amounts indicated below (in
thousand, except per share data):
2002 2001 2000
Compensation cost, net of
income taxes:
As reported $ 33 $ 92 $ 332
Pro forma 726 678 767
Net income:
As reported 30,024 21,938 37,183
Pro forma 29,331 21,352 36,748
Basic net income per share:
As reported 1.38 1.00 1.69
Pro forma 1.35 .97 1.67
Diluted net income per share:
As reported 1.37 .99 1.67
Pro forma 1.34 .97 1.65
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.
31
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
Summary of Significant Accounting Policies (cont'd)
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 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 but earlier implementation was
encouraged by the FASB and, therefore, the Company implemented
this standard in 2002. See Note 13.
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 became effective in the first
quarter of 2002 and its implementation had an immaterial impact
on the financial statements taken as a whole.
In the fourth quarter of 2002, the Company adopted the
supplemental disclosure requirements of SFAS No. 148, "Accounting
for Stock-Based Compensation - Transition and Disclosure", which
amended SFAS No. 123, "Accounting for Stock-Based Compensation."
The Company continues to record compensation related to employee
stock options based on the intrinsic value method per APB No. 25,
"Accounting for Stock Issued to Employees." SFAS No. 148
encourages companies to voluntarily elect to record the
compensation based on market value either prospectively as
defined in SFAS No. 123 or retroactively or in a modified
prospective method. Among other things, the Company is concerned
about the reasonableness of the market values determined using
the Black Scholes method. Therefore, the Company has delayed the
potential transition to recording stock compensation based on
fair market value until there is more clarity regarding the
measurement of stock option values.
Reclassifications
Certain reclassifications have been made to the 2001 and
2000 financial statements to conform with the 2002 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
$9.8 million and $6.4 million at December 31, 2002 and 2001,
respectively, are stated at cost, which approximates market.
The Company's short-term investments available for sale at
December 31, 2002 and 2001 consist of United States treasury
notes that mature in less than one year. The carrying value of
the Company's long-term debt is assumed to
32
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
3. Fair Value of Financial Instruments (cont'd)
approximate its fair value since it is carried at current
interest rates. For the three years ended December 31, 2002,
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 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 in the
Enron bankruptcy proceedings. 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.
To protect the Company's revenues from potential price
declines, the Company entered into hedge contracts in 2000 and
2002 covering 3,000 BPD to 6,500 BPD of its crude oil production.
The Company recorded losses of $3.8 million, $0 and $7.1 million
in 2002, 2001 and 2000, respectively, which were reported in
"Sales of oil and gas" in the Company's financial statements.
To protect a portion of the Company's electrical production
from low off-peak power prices, the Company entered into a series
of fixed price sale (swap) agreements on 30 Mwh per off-peak
hours which cover October 2002 through May 2003. In 2002, the
Company incurred losses of $.3 million which were recorded in
"Sales of electricity" in the Company's financial statements.
4. Concentration of Credit Risks
The Company sells oil, gas and natural gas liquids to
pipelines, refineries and major oil companies and electricity to
major utility companies. Credit is extended based on an
evaluation of the customer's financial condition and historical
payment record. 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, whereby the Company sold in
excess of 80% of its production under a negotiated pricing
mechanism. This contract was renegotiated during 2002 and
extended through December 31, 2005. Over 90% of the Company's
current production is subject to this new contract. Pricing in
the new agreement is based upon the higher of the average of the
local field posted prices plus a fixed bonus, or WTI minus a
fixed differential. Both methods are calculated using a monthly
determination. 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, 2002, 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. In March 2002, the Company was
paid the total amount due from SCE plus interest resulting in pre-
tax income of $4.2 million recorded in the first quarter of 2002
due to this collection.
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, 2002, the Company has not incurred losses
related to these investments. With respect to the Company's
hedging activities, the Company utilizes more than one
counterparty on its hedges and monitors each counterparty's credit
rating.
33
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
4. Concentration of Credit Risks (cont'd)
The following summarizes the accounts receivable balances at
December 31, 2002 and 2001 and sales activity with significant
customers for each of the years ended December 31, 2002, 2001 and
2000 (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
Customer December 31, December 31, For the Year Ended December 31,
2002 2001 2002 2001 2000
Oil & Gas
Sales:
A $ 10,714 $ 4,754 $ 94,870 $ 83,336 $ 87,613
B - 870 10,188 14,962 18,000
C 621 260 5,463 4,858 5,499
D - 5 - 157 12,390
E - - - - 13,080
------- ------- ------- ------- -------
$ 11,335 $ 5,889 $ 110,521 $ 103,313 $ 136,582
======= ======= ======= ======= =======
Electricity
Sales:
F $ 1,795 $ 9,873 $ 15,199 $ 21,257 $ 23,124
G - - - 6,859 26,769
H 1,573 812 12,317 6,279 -
------- ------- ------- ------- -------
$ 3,368 $ 10,685 $ 27,516 $ 34,395 $ 49,893
======= ======= ======= ======= =======
34
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):
2002 2001
Oil and gas:
Proved properties:
Producing properties, including
intangible drilling costs $ 180,942 $ 168,930
Lease and well equipment(1) 167,642 146,393
-------- --------
348,584 315,323
Less accumulated depreciation,
depletion and amortization 121,695 108,170
-------- --------
226,889 207,153
-------- --------
Commercial and other:
Land 173 173
Buildings and improvements 3,838 4,086
Machinery and equipment 3,922 3,634
-------- --------
7,933 7,893
Less accumulated depreciation 6,347 6,186
-------- --------
1,586 1,707
-------- --------
$ 228,475 $ 208,860
======== ========
(1)Includes cogeneration facility costs.
The following sets forth costs incurred for oil and gas property
acquisition and development activities, whether capitalized or
expensed (in thousands):
2002 2001 2000
Acquisition of properties/
facilities $ 5,880 $ 2,273 $ 3,204
Development 30,817 15,875 26,145
------- ------- -------
$ 36,697 $ 18,148 $ 29,349
======= ======= =======
In 2002, the Company acquired approximately 243,000 acres
for the potential development of coalbed methane (CBM) natural
gas production in Kansas and Illinois for a total of
approximately $5.9 million. The projects are in an early stage
of evaluation, with no significant production at December 31,
2002, and thus no reserves were recorded at year-end associated
with the acquired acreage. In 2001, the Company acquired a 15.8%
non-operated working interest in CBM natural gas properties in
Wyoming for $2.2 million and a producing property adjacent to
Berry's core Midway-Sunset properties for $.1 million.
Approximately 1.1 million equivalent barrels of proved reserves
were added by these acquisitions and subsequent development. The
2000 acquisition included the Castruccio property at the
Company's Placerita area which included 1.5 million barrels of
reserves.
35
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):
2002 2001 2000
Sales to unaffiliated parties $ 102,026 $ 100,146 $ 118,801
Production costs (44,604) (40,281) (46,789)
Depreciation, depletion and
amortization (16,124) (16,175) (13,712)
------- ------- -------
41,298 43,690 58,300
Income tax expenses (7,933) (10,740) (15,668)
------- ------- -------
Results of operations from
producing and exploration
activities $ 33,365 $ 32,950 $ 42,632
======= ======= =======
6. Debt Obligations
2002 2001 2000
Long-term debt for the years ended
December 31 (in thousands):
Revolving bank facility $ 15,000 $ 25,000 $ 25,000
======= ======= =======
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 unsecured loan.
At December 31, 2002 and 2001, the Company had $15 and $25
million, respectively, outstanding under the Agreement. In
addition to the $15 million in borrowings under the Agreement,
the Company has $5.2 million of outstanding Letters of Credit and
the remaining credit available under the Agreement is therefore,
$129.8 million at December 31, 2002. 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 lower of
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, 2002 was
2.25%. 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.
36
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
authorized the purchase of 100,000 shares of Berry Petroleum
Company Class A Common Stock until November 8, 2003 at $14.06 per
share. The Warrant was purchased from the holders in 2002 and
has been canceled.
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. No additional shares were repurchased
in 2002.
The Company issued 19,717, 6,529 and 21,325 shares in 2002,
2001 and 2000, respectively, through its stock option plan.
At December 31, 2002, 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):
2002 2000 2001
Current:
Federal $ 2,700 $ 3,108 $ 10,336
State 1,032 1,119 3,165
------- ------- -------
3,732 4,227 13,501
Deferred:
Federal 4,258 1,755 1,787
State (400) (682) (795)
------- ------- -------
3,858 1,073 992
------- ------- -------
Total $ 7,590 $ 5,300 $ 14,493
======= ======= =======
37
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):
2002 2001 2000
Deferred tax asset
Federal benefit of state
taxes $ 350 $ 392 $ 871
Credit/deduction
carryforwards 16,825 11,599 7,761
Other, net (1,205) 579 1,261
------- ------- -------
15,970 12,570 9,893
Deferred tax liability ------- ------- -------
Depreciation and depletion (50,829) (43,608) (39,894)
Other, net 173 210 246
------- ------- -------
(50,656) (43,398) (39,648)
------- ------- -------
Net deferred tax liability $(34,686) $(30,828) $(29,755)
======= ======= =======
Reconciliation of the statutory federal income tax rate to the
effective income tax rate follows:
2002 2001 2000
Tax computed at statutory
federal rate 35% 35% 35%
State income taxes, net of
federal benefit 1 1 2
Tax credits (15) (16) (11)
Other (1) (1) 2
---- ---- ----
Effective tax rate 20% 19% 28%
==== ==== ====
The Company has approximately $13 million of federal and $8
million of state (California) enhanced oil recovery (EOR) tax
credit carryforwards available to reduce future income taxes.
Total EOR credits of $1 million, $3 million, $8 million and $9
million will expire in 2014, 2015, 2016 and 2017, respectively.
38
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 of $36,692/month. In
February 2003, the Company leased an office in Denver through
March 2004 to assist in the Company's acquisition strategy, which
requires minimum rental payments of $2,307 per month. The total
minimum rental payments of both leases is as follows:
Year ending December 31,
2003 $ 464,861
2004 447,227
2005 440,305
2006 366,920
---------
Total $ 1,719,313
=========
Firm Transportation-Natural Gas Purchases
In 2001, the Company entered into a 12,000 Mmbtu/day firm
transportation agreement related to the expansion project on the
Kern River pipeline. This project is expected to be completed
with gas deliveries to commence in mid-2003. This firm
transportation provides the Company additional flexibility in
securing its natural gas supply and allows the Company to
potentially benefit from discounted natural gas prices in the
Rockies. This represents a 10-year, take-or-pay commitment of
approximately $31 million over the length of the contract.
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 and December 2001 (the
1994 Plan) and approved by the shareholders in May 1998 and May
2002, respectively. The 1994 Plan provides for the granting of
stock options to purchase up to an aggregate of 3,000,000 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.
39
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
11. Stock Option Plan (cont'd)
On December 6, 2002, February 1, 2002, December 7, 2001 and
December 1, 2000, 151,200, 40,000, 199,500 and 262,000 options,
respectively, were issued to eligible employees at an exercise
price of $16.50, $14.89, $16.30 and $15.69 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. The 1994
Plan also allows for option grants to the Board of Directors
under a formula plan whereby all non-employee Directors 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, 50,000, 40,000, and
40,000 options, respectively, were issued on December 2, 2002,
2001 and 2000, (5,000 options to each of the non-employee
Directors each year) at an exercise price of $16.14, $15.45 and
$15.69 per share, respectively.
The following is a summary of stock-based compensation
activity for the years 2002, 2001 and 2000.
2002 2001 2000
Options Options Options
Balance outstanding, January 1 1,474,962 1,407,837 1,220,630
Granted 241,200 239,500 302,000
Exercised (95,837) (65,125) (114,793)
Canceled/expired (15,750) (107,250) -
--------- --------- ---------
Balance outstanding, December 31 1,604,575 1,474,962 1,407,837
========= ========= =========
Balance exercisable at
December 31 1,153,000 1,010,712 872,587
========= ========= =========
Available for future grant 1,007,100 232,550 364,800
========= ========= =========
Exercise price-range $ 16.56 $ 14.40 $ 16.44
to to to
18.05 16.96 19.00
Weighted average remaining
contractual life (years) 7 7 8
Weighted average fair value
per option granted during the
year based on the Black-Scholes
pricing model $ 5.25 $ 5.87 $ 4.62
Weighted average option exercise price information for the
years 2002, 2001 and 2000 as follows:
2002 2001 2000
Outstanding at January 1 $ 14.80 $ 14.58 $ 14.15
Granted during the year 16.14 16.16 15.69
Exercised during the year 11.87 13.12 12.91
Expired during the year 15.92 16.01 -
Outstanding at December 31 15.17 14.80 14.58
Exercisable at December 31 14.81 14.55 14.50
40
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
12. Retirement Plan
The Company sponsors a 401(k) defined contribution thrift
plan to assist all eligible 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 2002, $.4
million in 2001 and $.5 million in 2000. On average,
approximately 94% of eligible employees participate in the plan.
13. Abandonment Obligation
In 2002, the Company implemented SFAS No. 143, "Accounting
for Asset Retirement Obligations" for recording future site
restoration costs related to its oil and gas properties. Prior
to its implementation, the Company had recorded future
abandonment obligations per SFAS No. 19, "Financial Accounting
and Reporting by Oil and Gas Producing Companies." As allowed
under SFAS No. 19, the Company's estimated costs, net of salvage
value, of plugging and abandoning oil and gas wells and related
facilities were accrued using the units-of-production method and
were taken into account when recording DD&A expense. Under SFAS
No. 143, the future retirement obligation is recorded at fair
value taking into consideration the Company's estimates of the
current abandonment liability, the inflation rate utilized to
inflate the current obligation to the estimated value at the end
of reserve lives, and the Company's credit-adjusted borrowing
rate used to discount the future value to a current fair value of
the obligation. The abandonment costs are recorded as part of
oil and gas properties and are depreciated using the units-of-
production method and the abandonment obligation is increased
each accounting period by recording accretion expense. In 2002,
the Company implemented this new standard which had an immaterial
effect on the Company's net income. The accrued abandonment
obligation at December 31, 2002 was $4.6 million. The recorded
abandonment obligation at December 31, 2001 under the previous
accounting method of $5.4 million was reclassified to a long-term
liability account in the current year presentation for
comparability purposes. It is anticipated that the charge to
income for future abandonment costs over the next several years
will be lower than the amounts previously accrued under SFAS No.
19. Using the fair value method required under SFAS No. 143, the
majority of the abandonment obligation is recorded toward the end
of the life of the producing assets.
14. Quarterly Financial Data (unaudited)
The following is a tabulation of unaudited quarterly operating
results for 2002 and 2001 (in thousands, except per share data):
Basic Diluted
net net
Operating Gross Net Income Income
2002 Revenues Profit Income Per Share Per Share
First Quarter $ 26,992 $ 8,014 $ 8,620 $ .40 $ .40
Second Quarter 32,045 10,482 6,827 .31 .31
Third Quarter 35,216 12,599 7,587 .35 .35
Fourth Quarter 36,600 10,534 6,990 .32 .32
------- ------- ------- ----- -----
$ 130,853 $ 41,629 $ 30,024 $ 1.38 $ 1.37
======= ======= ======= ===== =====
2001
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
======= ======= ======= ===== =====
41
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, 2002, 2001 and 2000. 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, 2002, 2001 and 2000, and changes in such quantities during
each of the years then ended were as follows (in thousands):
2002 2001 2000
Oil Gas Oil Gas Oil Gas
Mbbls Mmcf Mbbls Mmcf Mbbls Mmcf
Proved developed and
Undeveloped reserves:
Beginning of year 101,701 6,926 106,664 4,184 111,888 3,920
Revision of previous (30) (307) 33 153 (1,284) 463
estimates
Improved recovery 752 - - - - -
Extensions and 3,444 - - - - -
discoveries
Production (5,123) (769) (4,996) (288) (5,434) (199)
Purchase of reserves
in place - - - 2,877 1,494 -
------- ----- ------- ----- ------- -----
End of year 100,744 5,850 101,701 6,926 106,664 4,184
======= ===== ======= ===== ======= =====
Proved developed
reserves:
Beginning of year 79,317 3,518 81,132 1,635 86,717 1,371
======= ===== ======= ===== ======= =====
End of year 72,889 3,252 79,317 3,518 81,132 1,635
======= ===== ======= ===== ======= =====
42
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):
2002 2001 2000
Future cash inflows $ 2,533,410 $ 1,452,946 $ 2,268,932
Future production and development
costs (1,283,060) (699,505) (653,808)
Future income tax expenses (317,808) (184,064) (512,012)
--------- --------- ---------
Future net cash flows 932,542 569,377 1,103,112
10% annual discount for estimated
timimg of cash flows (480,355) (289,036) (599,530)
--------- --------- ---------
Standardized measure of discounted
future net cash flows $ 452,187 $ 280,341 $ 503,582
========= ========= =========
Pre-tax standardized measure of
discounted future net cash flows $ 602,157 $ 356,556 $ 721,770
========= ========= =========
Average sales prices at December 31:
Oil($/Bbl) $ 24.92 $ 14.16 $ 20.84
Gas($/Mcf) $ 3.94 $ 1.87 $ 10.97
Changes in standardized measure of discounted future net cash
flows from proved oil and gas reserves (in thousands):
2002 2001 2000
Standardized measure-beginning of year $ 280,341 $ 503,582 $ 496,482
-------- -------- --------
Sales of oil and gas produced, net of
production costs (57,422) (59,865) (72,358)
Revisions to estimates of proved reserves:
Net changes in sales prices and
production costs 288,870 (407,519) 98,744
Revisions of previous quantity estimates (560) 230 (9,295)
Improved recovery 5,159 - -
Extensions and discoveries 23,628 - -
Change in estimated future development
costs (74,566) 48,689 (78,328)
Purchases of reserves in place - 2,606 14,135
Development costs incurred during the 30,632 14,895 25,253
period
Accretion of discount 35,656 72,177 71,455
Income taxes (63,112) 135,792 (3,929)
Other (16,439) (30,246) (38,577)
-------- -------- --------
Net increase (decrease) 171,846 (223,241) 7,100
-------- -------- --------
Standardized measure - end of year $ 452,187 $ 280,341 $ 503,582
======== ======== ========
43
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, executive officers and beneficial owners of 10% or
more of any class of equity securities report to the Securities
and Exchange Commission changes in their beneficial ownership of
the Company's Capital 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 in 2002 that there has been
compliance with all Section 16(a) filing requirements except for
Mr. Busch who filed three late Form 4's for the sale of shares
from a trust at Union Bank.
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. Controls and Procedures
Within the 90 days prior to the date of this report, the
Company carried out an evaluation of the effectiveness of the
design and operation of the Company's disclosure controls and
procedures pursuant to Rule 13a-14 of the Securities Exchange Act
of 1934. Based upon that evaluation, the Chief Executive Officer
and Chief Financial Officer concluded that the Company's
disclosure controls and procedures are effective in timely
identifying material information potentially required to be
included in the Company's SEC filings.
There were no significant changes in the Company's internal
controls or other factors that could significantly affect these
controls subsequent to the date of their evaluation and there
were no corrective actions required with regard to significant
deficiencies and material weaknesses.
44
BERRY PETROLEUM COMPANY
Item 15. 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.
B. Reports on Form 8-K
On February 13, 2003, the Company filed a Form 8-K reporting
an Item 5. Other Event to furnish the Securities and Exchange
Commission a copy of the Company's earnings press release for the
year ended December 31, 2002.
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
(filed as Exhibit 10.1 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 2001, File No. 1-
9735).
10.2* Salary Continuation Agreement dated as of December 5, 1997,
by and between Registrant and Jerry V. Hoffman (filed as
Exhibit 10.2 to the Registrant's Annual Report on Form 10-K
for the year ended December 31, 1997, File No.1-9735)
10.3* Form of Salary Continuation Agreement dated as of December
5, 1997, by and between Registrant and Ralph J. Goehring
(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)
10.7* 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)
10.8* Amended and Restated 1994 Stock Option Plan (filed as
Exhibit 4.1 to the Registrant's Registration Statement on
Form S-8 filed on August 20, 2002, File No. 333-98379)
10.9** Crude oil purchase contract, dated as of August 1, 2002, by 50
and between the Registrant and Equiva Trading Company.
45
Exhibits (cont'd)
Exhibit Description of Exhibit
No. Page
10.10 Amended and Restated Non-Employee Director Deferred Stock 55
and Compensation Plan
23.1 Consent of PricewaterhouseCoopers LLP 62
23.2 Consent of DeGolyer and MacNaughton 63
99.1 Undertaking for Form S-8 Registration Statements 64
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)
99.4 Certification of Chief Executive Officer pursuant to 65
Section 906 of the Sarbanes-Oxley Act of 2002.
99.5 Certification of Chief Financial Officer pursuant to 66
Section 906 of the Sarbanes-Oxley Act of 2002.
* Incorporated by reference
** Pursuant to 17CFR240.24b-2, confidential information has been
omitted and has been filed separately with the Securities and
Exchange Commission, pursuant to a Confidential Treatment
Request filed with the Commission.
46
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 7, 2003.
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 Officer Accounting
Executive Officer (Principal Financial Officer)
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 7, 2003
Jerry V. Hoffman Director, President
& Chief Executive Officer
/s/ William F. Berry Director March 7, 2003
William F. Berry
/s/ Ralph B. Busch, III Director March 7, 2003
Ralph B. Busch, III
/s/ William E. Bush, Jr. Director March 7, 2003
William E. Bush, Jr.
/s/ Stephen L. Cropper Director March 7, 2003
Stephen L. Cropper
/s/ J. Herbert Gaul, Jr. Director March 7, 2003
J. Herbert Gaul, Jr.
/s/ John A. Hagg Director March 7, 2003
John A. Hagg
/s/ Robert F. Heinemann Director March 7, 2003
Robert F. Heinemann
/s/ Thomas J. Jamieson Director March 7, 2003
Thomas J. Jamieson
/s/ Martin H. Young, Jr. Director March 7, 2003
Martin H. Young, Jr.
47
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
I, Jerry V. Hoffman, Chairman, President and Chief Executive
Officer of Berry Petroleum Company, certify that:
1. I have reviewed this annual report on Form 10-K of Berry
Petroleum Company;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this annual report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant is made
known to us by others within the registrant, particularly during
the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors:
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have
indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: March 10, 2003
/s/ Jerry V. Hoffman
Jerry V. Hoffman
Chairman, President and
Chief Executive Officer
48
CERTIFICATION OF CHIEF FINANCIAL OFFICER
I, Ralph J. Goehring, Senior Vice President and Chief Financial
Officer of Berry Petroleum Company, certify that:
1. I have reviewed this annual report on Form 10-K of Berry
Petroleum Company;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for,
the periods presented in this annual report;
4. The registrant's other certifying officers and I are
responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant is made
known to us by others within the registrant, particularly during
the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors:
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have
indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that
could significantly affect internal controls subsequent to the
date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: March 10, 2003
/s/ Ralph J. Goehring
Ralph J. Goehring
Senior Vice President and
Chief Financial Officer
49
July 19, 2002 EQUIVA TRADING COMPANY
Berry Petroleum Company
5201 Truxtun Ave., Suite 300
Bakersfield, CA 93309-0640
Attention: Mr. Ron Cross Equiva Purchase Contract
Mr. Michael Duginski No.: BEP10132LP
Contract Dated: 8/01/02
Gentlemen:
THIS AGREEMENT is made and entered into by and between
EQUIVA TRADING COMPANY, a Delaware General Partnership ("Buyer"),
and BERRY PETROLEUM COMPANY, a Delaware Corporation, ("Seller")
acting for itself and in its capacity as the Operator of the
attached listed properties for the benefit of itself, and sets
forth the terms, conditions and provisions under which Seller
will sell and deliver and Buyer will purchase and receive certain
crude oil.
The crude oil that is sold and purchased under this
Agreement is that crude oil produced from the field wells located
within the area of the leases listed, which area consists of
lands covered by the oil and gas leases and/or other properties
that are specifically described on the Schedule of Covered
Producing Properties that is attached to this Agreement as
Exhibit B, all of which lands are located in California, to the
full extent, but only to the extent that Seller owns such crude
oil production or otherwise controls the right to market and sell
such crude oil production. Seller shall sell and deliver and
Buyer shall purchase and receive all such crude oil during the
delivery term provided for in this Agreement, all in accordance
with and subject to all of the terms, conditions and provisions
of this Agreement. However, nothing in this Agreement shall
obligate Seller to produce any particular volume of crude oil or
to produce any crude oil at all from any of the lands listed.
In addition to the foregoing, the terms, conditions and
provisions of this Agreement consist of and include the Special
Provisions attached to this Agreement as Exhibit A and the TTTI
General Provisions (December 1990), as modified by Buyer and
Seller and attached to this Agreement as Exhibit C. Each of
Exhibit A, Exhibit B, and Exhibit C are incorporated into and
made a part of this Agreement. In the event of any
inconsistencies between Exhibit A and Exhibit C, the terms,
conditions and provisions of Exhibit A (Special Provisions) shall
prevail.
IN WITNESS WHEREOF, Buyer and Seller have caused this
Agreement to be executed in duplicate on the date set forth
opposite their respective signatures.
Please return one fully executed original of this Agreement
to the attention of Contract Administrator.
Very truly yours,
BERRY PETROLEUM COMPANY EQUIVA TRADING COMPANY
By: s/s Michael Duginski By: s/s Jimmy French
Michael Duginski Jimmy French
Vice President Manager, Crude Oil Acquisitions
U.S. West Coast
Corporate Development
Date: 30/July/02 By: s/s Mike Purdy
Mike Purdy
Manager Lease Crude Oil
Acquisitions
Date: 7/30/02
EXHIBIT 10.9 Page 1 of 5
1
BEP10132LP 7/19/2002
Dated: 8/01/02
EXHIBIT A
Berry Petroleum Company, Inc
Contact: Ron Cross Equiva Contact: Mike Purdy
Phone: 661-616-3821 Phone: 661-328-2311
Berry Petroleum Company, Inc Sale and Delivery to Equiva:
Amends Supercedes Contract BEP1011LP Midway Sunset
Supercedes Contract BEP1010LP Placerita
Supercedes Contract BEP1005CP Montalvo
Quality Midway Sunset merchantable oil (approximately
13 gravity).
Placerita merchantable oil (approximately 13
gravity ).
Montalvo merchantable oil (approximately
27gravity).
Quantity Approximately 15,000b/d of oil from Midway
Sunset, Placerita, & Montalvo fields as described
in Exhibit B.
Delivery From lease tankage into Equiva Trading Company
point nominated pipeline, transfer line, or truck crude
carrier. Measurement shall be by appropriate ASTM
designated custody transfer method.
Term This contract shall be in effect August 1,
2002. The new contract pricing set forth below for
all of the volume shall begin on the first day of
the first month the additional Formax volume can be
added to the contract volume. Until such time as
100% of the Formax crude is nominated to Equiva, the
pricing terms defined in contracts BEP1011LP,
BEP1010LP and BEP1005CP shall remain in effect. This
contract shall continue until December 31, 2005 and
month to month thereafter until the first of the
month following either company's sixty (60) day
advanced written notice of termination. The payment
due date shall be on or before the 20th day of the
month following the delivery month.
Pricing All heavy barrels from Midway Sunset &
Midway Sunset Placerita shall be priced monthly at the higher of
& Placerita 1) the Monthly Calendar average NYMEX LESS [*] OR 2)
the average of Chevron, Union 76, Exxon/Mobil, and
Equiva Trading Company's posting for Midway-Sunset
Pricing crude PLUS a premium of [*] per barrel with either
Montalvo price being gravity adjusted from 13 degrees.
The Montalvo light barrels produced from the
McGrath 4 Pool lease shall be priced at the monthly
calendar average of postings by Union 76 and Equiva
Trading Company for Ventura Avenue Crude, gravity
adjusted from 28 degrees, PLUS a premium of [*] per
barrel. Montalvo light barrels in excess of 100 BOPD
monthly average shall incur a transportation charge
of [*] per barrel.
[*] represents confidential material which
has been redacted. A Confidential
Treatment Request, including the redacted
material, has been filed separately with
the Commission pursuant to Rule 24b-2 of
the Securities Exchange Act of 1934, as amended.
New Volumes The approximate volume of the total purchase is
15,000 b/d +/- as described in Exhibit B. Montalvo
lease light oil is being added to this contract.
Berry Petroleum shall have the right to add
additional volumes of San Joaquin Valley heavy crude
of similar type and quality as the crude being
produced from Berry's Midway Sunset properties ("New
Volume"). [*] In the event of New Volume there
shall be no transportation charge for delivery from
the Berry Central Facility and delivery from any
other point may incur a transportation charge as the
parties may mutually agree at the time any New
Volume is added to this Contract to reflect added
distance to the Shell pipeline compared to distance
from the Berry Central Facility to the Shell
pipeline.
[*] represents confidential material which
has been redacted. A Confidential
Treatment Request, including the redacted
material, has been filed separately with
the Commission pursuant to Rule 24b-2 of
the Securities Exchange Act of 1934, as amended.
Assignment Should Berry Petroleum Company be acquired or
and merged into another entity, this contract shall
Succession remain in effect for the succeeding entity. Should
Equiva Trading Company be acquired or merged into
another entity, this contract shall remain in effect
for the succeeding party. Neither Party shall assign
the Agreement or its rights hereunder without prior
written consent of the other Party.
All Other All other terms and conditions shall remain
Terms the same.
2 EXHIBIT 10.9 Page 2 of 5
Equiva Purchase Contract No.: BEP10132LP
Dated: 8/01/02
EXHIBIT B
CUSTOMER NAME: Berry Petroleum Company, Inc
EQUIVA TRADING COMPANY
ETCO CONTRACT NO.:
CONTRACT DATE: 9/01/02
APPROX.
LEASE LEASE August 2002
NUMBER PROPERTY NAME COUNTY FIELD TERMS TOTAL DELIVERY TRANSPORTATION METHOD
52485 Central Kern Midway SS 8/1/02- 7000 Equiva design. PPL
Facility 12/31/05
01817 Formax Kern Midway SS 8/1/02- 3200 Equiva design. PPL
12/31/05
Various NMWSS Kern Midway SS 8/1/02 - 550 Equiva designated PPL
12/31/05
01733 Ethel D Kern Midway SS 8/1/02- 125 Equiva design. PPL
12/31/05
52312 Placerita Los Angeles Placerita 8/1/02- 3,000 Equiva design. trucks
12/31/05
52329 McGrath #4 Ventura Montalvo 8/1/02- 50 Equiva design. trucks
12/31/05
EXHIBIT 10.9 Page 3 of 5
ATTACHMENT C ETCO CONTRACT NO.: BEP10132LP CONTRACT DATE:
8/01/02
TEXACO TRADING & TRANSPORTATION, INC.
GENERAL PROVISIONS
SPECIFIC TERMS: The specific terms of the Contracts between the
Buyer and the Seller, including a description of the crude oil,
condensate and/or natural gas liquids (`liquid hydrocarbons")
subject thereto, quantity, price, shipment and payment terms, are
set forth in specific Agreements between the Buyer and the
Seller, which, together with the printed terms below, constitute
integrated Contracts between the parties. In the event of any
inconsistency between the printed terms below and such specific
terms, the specific terms shall prevail.
WARRANTY/TAXES: The Seller warrants good title to all liquid
hydrocarbons delivered pursuant to this Contract and warrants
that such shall be free from all royalties, liens, encumbrances
and all applicable foreign, Federal, State and local taxes that
are imposed upon the production and/or removal of liquid
hydrocarbons from the premises through the point of delivery.
Seller further warrants that such liquid hydrocarbons have been
produced, handled and transported to the point of delivery in
accordance with all applicable laws, rules and regulations of all
Federal, State and local authorities. Seller further warrants
that all liquid hydrocarbons will be merchantable. Merchantable
liquid hydrocarbons are defined as unrefined liquid hydrocarbons
of the type set forth in the specific Agreements between the
parties which are suitable for normal refinery processing, meet
the specifications of delivering carriers and are free of foreign
contaminants and chemicals including but not limited to
chlorinated and oxygenated hydrocarbons. Buyer shall be liable
for and shall remit to the proper government authorities any new
or additional Federal, State, municipal or other regulatory
body's taxes, inspection fees, transfer taxes or fees, occupation
taxes or other like assessments or charges that may be applicable
to liquid hydrocarbons after the point of delivery. If any tax
imposed by 26 U.S.C. Sec. 4611 (the tax on petroleum under the
Superfund Amendments and Reauthorization Act of 1986) shall be
applicable after the point of delivery to a purchase, sale or
exchange pursuant to this Contract, the Buyer shall be liable for
payment and shall be responsible for remittance of such tax to
the appropriate governmental authority.
TITLE AND RISK OF LOSS: Title to, possession of and risk of loss
of liquid hydrocarbons shall pass to the Buyer as the liquid
hydrocarbons pass from equipment or location owned or controlled
by the Seller or owned or controlled by a Party designated to
make delivery on behalf of the Seller, into equipment owned or
controlled by the Buyer or owned or controlled by a Party
designated to take delivery on behalf of the Buyer. Provided,
however, that in cases of line transfers, title to, possession of
and risk of loss of liquid hydrocarbons shall pass to Buyer as
the liquid hydrocarbons are deemed transferred. Such shall be
deemed transferred to Buyer upon completion of each in line
transfer with quantity determined when available in accordance
with the transfer statement or other receipt issued by the
carrier or storage facility.
EQUAL DELIVERIES: For purposes of determining price, liquid
hydrocarbons delivered during any given month hereunder shall be
deemed to have been delivered in equal daily quantities during
such month.
MEASUREMENTS AND TESTS: All measurement hereunder shall
represent one hundred percent (100%) volume with such volume and
gravity adjusted to sixty degrees (60) Fahrenheit temperature.
Procedures for measuring and testing, except for deliveries
through positive displacement-type delivery, shall be according
to ASTM published methods then in effect. Procedures for such
metered-type delivery shall be according to latest ASME-API
published methods then in effect. The liquid hydrocarbons
delivered hereunder shall be merchantable and acceptable to the
carriers involved, and full deduction shall be made for all BS&W
content according to the latest ASTM standard method then in
effect. Should either Party hereto fail to have a representative
present during such measuring and testing, the measurements and
tests of the other Party will be accepted.
CONFIRMATION OF DELIVERY: Confirmation of delivery shall be
based on run tickets evidencing such delivery or allocations
statements issued by the carriers involved.
CONFIRMATION OF EXCHANGE BALANCES: If this Contract is for the
exchange of liquid hydrocarbons and is in effect within sixty
(60) days after delivery thereunder is completed, each Party
agrees to confirm in writing to the other Party the status in
barrels of liquid hydrocarbons of mutual and reciprocal
obligations to deliver liquid hydrocarbons.
DIVISION ORDERS: In the event either Party signs a division
order in favor of the other Party pertaining to the object of
this Contract, the terms of this Contract shall supersede the
terms of such division order to the extent there may be a
conflict between the two.
FINANCIAL RESPONSIBILITY: Should Buyer's credit or financial
responsibility become unsatisfactory to Seller at any time while
a Contract is in effect between the parties, cash payments or
security satisfactory to Seller may be required by Seller before
proceeding. In the event either Party (the "Non-Performing
Party") shall (I) make an assignment or any general arrangement
for the benefit of credits, (II) default in the payment or
performance of any Contract between the parties, (III) file a
petition or otherwise commence or authorize the commencement of a
proceeding or case under any bankruptcy or similar law for the
protection of creditors or have such petition filed or proceeding
commenced against it, (IV) otherwise become bankrupt or insolvent
(however evidenced), (V) be unable to pay its debts as they fall
due, or (VI) fail to give adequate security for or assurance of
its ability to perform its obligation under any Contract between
the parties within 48 hours of a reasonable request therefor,
then in any such event, the other Party (the "Performing Party")
shall have the right to (I) withhold shipments or terminate any
or all Contracts between the parties without notice, and/or (II)
immediately liquidate any or all forward Contracts then
outstanding between the parties by closing out each such forward
Contract by buying from the Non-Performing Party the material
purchased and sold thereunder and calculating market damages
equal to the differences, if any, between the value specified in
such Contract and the then prevailing market rates as reasonable
determined by the Performing Party, setting off all market
damages so determined and payable by each of the parties to the
other, setting off all margin held by either Party to secure the
obligations of the other Party, (including all payments due the
other Party with respect to deliveries received from such other
Party, which payments, prior to payment, shall be deemed to be
held by each Party as margin to secure the other Party's
obligations from time to
EXHIBIT 10.9 Page 3 of 5
time incurred), whereupon all such
amounts shall be aggregated or netted to a single liquidated
amount payable within one business day by the Party owing the
greater such amount to the other. The exercise by either Party
of any right reserved under this section shall be in addition to
and not in limitation or exclusion of any other rights which such
Party may have (whether by operation of law or otherwise)
including any rights and remedies under the Uniform Commercial
Code.
ASSIGNMENT: Neither Party shall assign this Contract without the
prior written consent of the other.
TERMINATION AGREEMENT: The parties agree that any quantity of
liquid hydrocarbons due and owing or to become due from one Party
to the other pursuant to this Contract may be waived or otherwise
settled by mutual agreement of the parties, in writing.
FORCE MAJEURE: Neither Party shall be liable to the other for
failure or delay in making or accepting delivery hereunder to the
extent that such failure or delay may be due to compliance with
acts, orders, regulations or requests of any Federal, State or
local civilian or military authority or any other persons
purporting to act therefor; riots; strikes; labor difficulties;
action of the elements; transportation difficulties; or any other
cause reasonably beyond the control of such Party, whether Seller
or not. For the purposes of this section, the term "Party" shall
be defined to include Seller's supplier and Buyer's receiver.
Seller shall not be obligated to make up any deliveries omitted
as a result of any of the causes enumerated in this section
except that Seller and Buyer are required to reconcile or balance
zero value exchanges. In the event either Party is claiming
(Telex or other electronic communication acceptable) with as much
advance notice as is possible the underlying circumstances of the
particular cause(s) of Force Majeure and the expected duration
thereof and notwithstanding the provisions of this section, Buyer
shall not be relieved of any obligation to make payments with
regard to liquid hydrocarbons that have been delivered hereunder.
GOVERNING LAW AND JURISDICTION: This Contract shall be construed
and governed by the laws of the State of California to the
exclusion of any other legal system, and each Party expressly
submits to the jurisdiction venue of the courts of the State of
California or the federal courts in Colorado for the purposes of
litigation.
NEW OR CHANGED REGULATIONS: Each of the parties hereto is
entering this Contract in reliance on the laws, taxes, fees,
duties, rules, regulations, decrees, agreements, concessions and
arrangements with government or governmental instrumentalities
(the "Regulations") in effect on the date of this Contract which
directly or indirectly affect the oil sold and to be delivered
hereunder insofar as these Regulations affect the Seller, the
Seller's supplier, the Buyer or the receiver.
In the event that during the term of this Contract any of the
Regulations or changed or new Regulations become effective and
the effect of such new or changed Regulations is not covered by
any other provision of this Contract and said change has a
material adverse economic impact upon the parties named above,
the Party affected or if the Seller's supplier, the Seller, or if
the Buyer's receiver, the Buyer, in the exercise of good faith
shall have the option to request renegotiations of the prices
and/or other relevant terms of this Contract with respect to
deliveries not yet made. In the event the Buyer or Seller is in
good faith dissatisfied with the results of the renegotiation,
either Party will have the right to cancel this Contract if
notice of such cancellation is given in writing to the other
Party within thirty (30) days of the effective date of (I) the
change of the Regulations or (II) the new Regulations.
PAYMENT: Seller and Buyer shall use as a basis for payment for
the liquid hydrocarbons delivered run tickets or any acceptable
ASTM measurement method. Those tickets shall be delivered by the
responsible party as soon as possible after the close of each
calendar month during which deliveries are made but not later
than five business days prior to payment due date. Payment shall
be in immediately available US Dollars. Payments due on Saturday
or bank holidays shall be made on the preceding business day,
unless such holiday is a Monday in which case payment shall be
made on the following business day; payments due on Sunday shall
be made on the following business day. Past due accounts shall
accrue interest at the published rate for commercial loans quoted
by Morgan Guaranty Trust Company of New York.
RIGHTS OF SETOFF: In the event that either Party shall default
in any payment or other performance under this or any other
Contract existing by and between the parties hereto, or if any
suit, claim, demand, action or cause of action shall be
instituted involving any sums due under this or any other such
Contract, then and in any of these events, the other Party, at
its option, shall have the right to withhold any payments or any
deliveries of liquid hydrocarbons due under this or any other
such Contract, or offset and deduct from any payments of
deliveries due under this or any other such Contract.
AUDIT: Each Party and its duly authorized representatives shall
have access to the accounting records and other documents
maintained by the other Party which relate to this Contract, and
shall have the right to audit such records at any reasonable time
or times within three years after termination of this Contract.
WAIVER: No waiver by either Party of any breach of any of the
covenants or conditions herein contained to be performed by the
other Party shall be construed as a waiver of any succeeding
breach of the same or of any covenant or condition hereof.
TIMING: References to calendar dates set forth in this Contract
and any amendments hereto, shall mean 7:00 A.M. of the dates
indicated.
EXHIBIT 10.9 Page 5 of 5
BERRY PETROLEUM COMPANY
NON-EMPLOYEE DIRECTOR
DEFERRED STOCK AND COMPENSATION PLAN
(as amended December 6, 2002)
Section 1. Establishment of Plan; Purpose. The Berry
Petroleum Company Non-Employee Director Deferred Stock and
Compensation Plan (the "Plan") is hereby established to permit
Eligible Directors, in recognition of their contributions to the
Company (a) to receive Shares in lieu of Compensation and
(b) to defer recognition of their Compensation in the manner
described below. The Plan is intended to enable the Company to
attract, retain and motivate qualified directors and to enhance
the long-term mutuality of interest between Directors and
stockholders of the Company.
Section 2. Definitions. When used in this Plan, the
following terms shall have the definitions set forth in
this Section:
2.1. "Accounts" shall mean an Eligible Director's Stock Unit
Account and Interest Account.
2.2. "Board of Directors" shall mean the Board of Directors of
the Company.
2.3. "Committee" shall mean the Compensation Committee of the
Board of Directors or such other committee of the Board as the
Board shall designate from time to time.
2.4. "Company" shall mean Berry Petroleum Company, a Delaware
corporation.
2.5. "Compensation" shall mean (a) the fee earned by an Eligible
Director for service as a Director; (b) the fee, if any, earned
by an Eligible Director for service as a member of a committee of
the Board of Directors; and (c) the fee earned by an Eligible
Director for (i) attendance at meetings of the Board of Directors
and (ii) attendance at meetings of committees. All Compensation
earned by an Eligible Director for the services identified in
subsections (a), (b) and (c) above, shall be deemed earned by an
Eligible Director and credited to the designated Accounts on the
last trading day of the fiscal quarter in which such service was
provided.
2.6. "Director" shall mean any member of the Board of Directors,
whether or not such member is an Eligible Director.
2.7. "Effective Date" shall mean the date on which the Plan is
approved by the stockholders of the Company.
2.8. "Eligible Director" shall mean a member of the Board of
Directors who is not an employee of the Company.
1 EXHIBIT 10.10 Page 1 of 7
2.9. "Exchange Act" shall mean the Securities Exchange Act of
1934, as amended.
2.10. "Fair Market Value" shall mean the closing price of a
Share as reported by the New York Stock Exchange on the last
trading day of such fiscal quarter on which such value is to be
determined under this Plan.
2.11. "Interest Account" shall mean the bookkeeping account
established to record the interests of an Eligible Director with
respect to deferred Compensation that is not allocated to Units
in a Stock Unit Account.
2.12. "Shares" shall mean shares of Stock.
2.13. "Stock" shall mean the Class A Common Stock of the
Company.
2.14. "Stock Unit Account" shall mean a bookkeeping account
established to record the interests of an Eligible Director who
has elected to have deferred Compensation credited as Units in
this Account.
2.15. "Unit" shall mean a contractual obligation of the
Company to deliver a Share, or pay cash, based on the Fair Market
Value of a Share to an Eligible Director or the beneficiary or
estate of such Eligible Director as provided herein.
Section 3. Administration
. The Plan shall be administered by the Committee;
provided, however, that the Plan shall be administered such that
any Director participating in the Plan shall continue to be
deemed to be a "disinterested person" under Rule 16b-3 of the
Securities and Exchange Commission under the Exchange Act ("Rule
16b-3"), as such Rule is in effect on the Effective Date of the
Plan and as it may be subsequently amended, for purposes of such
Director's ability to serve on any committee charged with
administering any of the Company's stock-based incentive plans
for executive officers intended to qualify for the exemptive
relief available under Rule 16b-3.
Section 4. Shares Authorized for Issuance.
4.1. Maximum Number of Shares. The aggregate number of
Shares which may be issued to Eligible Directors under the
Plan shall not exceed Two Hundred Fifty Thousand (250,000)
Shares, subject to adjustment as provided in Section 4.2
below. If any Unit is distributed in cash or is forfeited
without a distribution of Shares, the Shares otherwise
subject to such Unit shall again be available
hereunder.
4.2. Adjustment for Corporate Transactions. If the outstanding
Stock is increased, decreased, changed into or exchanged for a
different number or kind of shares of the Company through
reorganization, recapitalization, reclassification, stock dividend,
stock split or reverse stock split, an appropriate and
proportionate adjustment shall be made in the number or kind of
shares which may be issued in the aggregate under this Plan and
the number of Units that have been, or may be, issued under this
Plan; provided, however, that no such adjustment need be made if,
upon the advice of counsel, the Committee determines that such
adjustment may result in the receipt of federally taxable income
to holders of Stock or other classes of the
2 EXHIBIT 10.10 Page 2 of 7
Company's equity securities. The nature and extent of such
adjustments shall be determined by the Committee in its sole
discretion, and any such determination as to what adjustments
shall be made, and the extent thereof, shall be final, binding
and conclusive. No fractional shares of Stock shall be issued
under this Plan pursuant to any such adjustment.
Section 5. Deferred Compensation Program.
5.1. Election to Defer. On or before December 31 of any
calendar year, an Eligible Director may elect to defer receipt of
all or any part of any Compensation payable in respect of the
calendar year following the year in which such election is made,
and to have such amounts credited, in whole or in part, to a Stock
Unit Account or an Interest Account. Any person who shall become
an Eligible Director during any calendar year may elect, not later
than the 30th day after his term as a Director begins, to defer
payment of all or any part of his Compensation payable for the
portion of such calendar year following such election. In the
year in which this Plan is first implemented, any Eligible
Director may elect, not later than the 30th day after the
Effective Date, to defer payment of all or any part of his
Compensation payable for the portion of such calendar year
following the Effective Date.
5.2. Method of Election. A deferral election shall be made by
written notice filed with the Corporate Secretary of the Company.
Such election shall continue in effect (including with respect
to Compensation payable for subsequent calendar years) unless
and until the Eligible Director revokes or modifies such election
by written notice filed with the Corporate Secretary. Any such
revocation or modification of a deferral election shall become
effective as of December 31 of the year in which such notice is
given and only with respect to Compensation payable in respect
of the calendar year following the year in which just revocation
or modification is made; provided however that if the effect
of such revocation or modification of a deferral election is to
change the amount of deferred Compensation that would otherwise
have been credited to the Stock Unit Account it shall in no event
become effective earlier than six (6) months after it is received
by the Corporate Secretary. Amounts credited to the Eligible
Director's Stock Unit Account prior to the effective date of any
such revocation or modification of a deferral election shall not
be affected by such revocation or modification and shall be
credited and distributed only in accordance with the deferral
election in place prior to such revocation and modification and
otherwise in accordance with the applicable terms of the Plan.
An Eligible Director who has revoked an election to participate
in the Plan may file a new election to defer Compensation with
respect to services rendered in the calendar year following the
year in which such new election is filed with the Corporate
Secretary of the Company.
5.3. Investment Election. At the time an Eligible Director
elects to defer receipt of Compensation pursuant to Section 5.1,
the Eligible Director shall also designate in writing the portion
of such Compensation, stated as a whole percentage, to be
credited to the Interest Account and the portion to be credited
to the Stock Unit Account. If an Eligible Director fails to
designate the allocation between the two Accounts, 100% of such
Compensation shall be credited to the Interest Account. By
written notice to the Corporate Secretary, an Eligible Director
may change the investment election and the manner in which
Compensation is allocated among the Accounts but only with
respect to services to be rendered in the calendar year following
the year in which such new investment election is filed with the
Corporate Secretary,
3 EXHIBIT 10.10 Page 3 of 7
provided that any such election shall only be effective with
respect to Compensation payable six (6) months after such new
investment election is received by the Corporate Secretary.
5.4. Interest Account.
a. Any Compensation allocated to an Eligible Director's
Interest Account shall be deemed earned and credited to the
Interest Account as of the last trading day of the fiscal quarter
in which the service was provided for which such compensation
amount would have been paid to the Eligible Director.
b. Any amounts credited to the Interest Account shall be
credited with interest at the rate of five percent (5%) per
annum, compounded annually.
5.5. Stock Unit Account.
a. Any Compensation allocated to an Eligible Director's Stock
Unit Account shall be deemed earned and credited to Units in the
Stock Unit Account as of the last trading day of the fiscal
quarter in which the service was provided for which such
compensation amount would have been paid to the Eligible
Director.
b. The number of Units allocated to the Eligible Director's
Stock Unit Account pursuant to subsection (a) above shall be
equal to the quotient of (i) the aggregate Compensation allocated
to the Stock Unit Account as of the last trading day of the
fiscal quarter divided by (ii) the Fair Market Value on the last
trading day of such quarter. Fractional Units shall be credited,
but shall be rounded to the nearest hundredth percentile, with
amounts equal to or greater than .005 rounded up and amounts less
than .005 rounded down.
5.6. Dividend Equivalents.
a. An Eligible Director who has elected to defer Compensation
to a Stock Unit Account shall have no rights as a stockholder of
the Company with respect to any Units until Shares are
distributed and delivered to the Eligible Director.
b. Notwithstanding the provisions of subsection (a), each
Eligible Director who has allocated Compensation to a Stock Unit
Account shall have the right to receive an amount equal to the
dividend per Share declared by the Company on the applicable
dividend payment date (which, in the case of any dividend
distributable in property other than Shares, shall be the per
Share value of such dividend, as determined by the Company for
purposes of income tax reporting) times the number of Units held
by such Eligible Director in his Stock Unit Account (a "Dividend
Equivalent").
c. Each Eligible Director may designate in writing to the
Corporate Secretary, prior to any calendar year, whether any
Dividend Equivalent is to be: (i) payable in cash, on or as soon
as practicable after each date on which dividends are paid to
stockholders with respect to Shares; (ii) deferred and credited
to the Eligible Director's Interest Account; or (iii) treated as
reinvested in an additional number of Units and credited to the
Eligible Director's Stock Unit Account.
4 EXHIBIT 10.10 Page 4 of 7
d. The additional number of Units to be credited to the
Eligible Director's Stock Unit Account pursuant to (c) (iii)
shall be determined by dividing (i) the product of (A) the number
of Units in the Eligible Director's Stock Unit Account on the
date the dividend is declared, and (B) the amount of any cash
dividend declared by the Company on a Share (or, in the case of
any dividend distributable in property other than Shares, the per
share value of such dividend, as determined by the Company for
purposes of income tax reporting), by (ii) the Fair Market Value
on the last trading day of the fiscal quarter in which the
dividend is declared.
e. Notwithstanding the date used for purposes of determining
the number of additional Units as provided in subsection (d)
above, the additional Units to be credited for Dividend
Equivalents shall be deemed earned and credited to the Eligible
Director's Stock Unit Account on the last trading day of the
fiscal quarter in which such dividend is declared.
f. In the event of any stock split, stock dividend,
recapitalization, reorganization or other corporate transaction
affecting the capital structure of the Company, the Committee
shall make such adjustments to the number of Units credited to
each Eligible Director's Stock Unit Account as the Committee
shall deem necessary or appropriate to prevent the dilution or
enlargement of such Eligible Director's rights and such
adjustment shall be made and effective as of the last day of the
fiscal quarter in which such corporate transaction has occurred.
5.7. Distribution Election.
a. At the time an Eligible Director makes a deferral election
pursuant to Section 5.1, the Eligible Director shall also file
with the Corporate Secretary a written election (a "Distribution
Election")
b. The Distribution Election shall specify the aggregate
amount, if any, credited to the Interest Account at any time and
the value of any Units credited to the Stock Unit Account shall
be distributed (i) in cash, (ii) in Shares or (iii) in a
combination thereof, provided further that any election to
receive a distribution of all or any portion of the value of an
Eligible Director's Interest Account in Shares must be made on an
irrevocable basis at least six (6) months in advance of such
distribution.
c. Such distribution shall commence, at the election of the
Eligible Director, as soon as practicable following the first
business day of the calendar month following the date the
Eligible Director ceases to be a Director or on the first
business day of any calendar year following the calendar year in
which the Eligible Director ceases to be a Director.
d. Such distribution shall be in one lump sum payment or in
such number of annual installments (not to exceed ten (10)) as
the Eligible Director may designate. The amount of any
installment payment shall be determined by multiplying the amount
credited to the Accounts of an Eligible Director immediately
prior to the distribution by a fraction, the numerator of which
is one and the denominator of which is the number of installments
(including the current installment) remaining to be paid.
5 EXHIBIT 10.10 Page 5 of 7
e. An Eligible Director may at any time prior to the time at
which the Eligible Director ceases to be a Director, and from
time to time, change any Distribution Election applicable to his
Accounts, provided that no election to change the timing of any
final distribution shall be effective unless it is made in
writing and received by the Corporate Secretary at least one (1)
year prior to the time at which the Eligible Director ceases to
be a director.
5.8. Financial Hardship Withdrawal. Any Eligible Director may,
after submission of a written request to the Corporate Secretary
and such written evidence of the Eligible Director's financial
condition as the Committee may reasonably request, withdraw from
his Interest Account (but not from his Stock Unit Account) up to
such amount as the Committee shall determine to be necessary
to alleviate the Eligible Director's financial hardship.
5.9. Timing and Form of Distributions.
a. Any distribution to be made hereunder, whether in the form
of a lump sum payment or installments, following the termination
of an Eligible Director's service as a Director shall commence in
accordance with the Distribution Election made by the Eligible
Director pursuant to Section 5.7.
b. If an Eligible Director fails to specify a form of payment
for a distribution in accordance with Section 5.7, the
distribution from the Interest Account shall be made in cash and
the distribution from the Stock Unit Account shall be made in
Shares.
c. If an Eligible Director fails to specify in accordance with
Section 5.7 a commencement date for a distribution or whether
such distribution shall be made in a lump sum payment or a number
of installments, such distribution shall be made in a lump sum
payment and commence on the first business day of the month
immediately following the date on which the Eligible Director
ceases to be a Director. In the case of any distribution being
made in annual installments, each installment after the first
installment shall be paid on the first business day of each
subsequent calendar year, or as soon as practical thereafter,
until the entire amount subject to such Distribution Election
shall have been paid.
Section 6. Unfunded Status. The Company shall be under
no obligation to establish a fund or reserve in order to pay the
benefits under the Plan. A Unit represents a contractual
obligation of the Company to deliver Shares or pay cash to an
Eligible Director as provided herein. The Company has not
segregated or earmarked any Shares or any of the Company's assets
for the benefit of an Eligible Director or his beneficiary or
estate, and the Plan does not, and shall not be construed to,
require the Company to do so. The Eligible Director and his
beneficiary or estate shall have only an unsecured, contractual
right against the Company with respect to any Units granted or
amounts credited to an Eligible Director's Accounts hereunder,
and such right shall not be deemed superior to the right of any
other creditor. Units shall not be deemed to constitute options
or rights to purchase Stock.
Section 7. Amendment and Termination. The Plan may be
amended at any time by the Committee or the Board of Directors.
Any modification of any of the terms and provisions of the Plan,
including this Section, shall not be made more than once every
six (6)
6 EXHIBIT 10.10 Page 6 of 7
months. The Plan shall terminate on May 31, 2008.
Unless the Board otherwise specifies at the time of such
termination, the termination of the Plan will not result in the
premature distribution of the amounts credited to an
Eligible Director's Accounts.
Section 8. General Provisions.
8.1. No Right to Serve as a Director. This Plan shall not
impose any obligations on the Company to retain any Eligible
Director as a Director nor shall it impose any obligation on the
part of any Eligible Director to remain as a Director of the
Company.
8.2. Rights of a Terminated Director. Notwithstanding the fact
that an Eligible Director ceases to be a director during any
fiscal quarter, the Eligible Director's Accounts shall be
credited, on the last trading day of the fiscal quarter, with all
Compensation and Dividend Equivalents earned as of the last
business day he served as an Eligible Director.
8.3. Construction of the Plan. The validity, construction,
interpretation, administration and effect of the Plan and the
rights relating to the Plan, shall be determined solely in
accordance with the laws of the State of Delaware.
8.4. No Right to Particular Assets. Nothing contained in this
Plan and no action taken pursuant to this Plan shall create or be
construed to create a trust of any kind or any fiduciary
relationship between the Company and any Eligible Director, the
executor, administrator or other personal representative or
designated beneficiary of such Eligible Director, or any other
persons. Any reserves that may be established by the Company
in connection with Units granted under this Plan shall continue
to be treated as the assets of the Company for federal income tax
purposes and remain subject to the claims of the Company's
creditors. To the extent that any Eligible Director or the
executor, administrator, or other personal representative of such
Eligible Director, acquires a right to receive any payment from
the Company pursuant to this Plan, such right shall be no greater
than the right of an unsecured general creditor of the Company.
8.5. Severability of Provisions. If any provision of this Plan
shall be held invalid or unenforceable, such invalidity or
unenforceability shall not affect any other provisions hereof,
and this Plan shall be construed and enforced as if such provision
had not been included.
8.6. Incapacity. Any benefit payable to or for the benefit of
a minor, an incompetent person or other person incapable of
receipting therefor shall be deemed paid when paid to such
person's guardian or to the party providing or reasonably
appearing to provide for the care of such person, and such
payment shall fully discharge any liability or obligation of
the Board of Directors, the Company and all other parties with
respect thereto.
8.7. Headings and Captions. The headings and captions
herein are provided for reference and convenience only, shall
not be considered part of this Plan, and shall not be employed
in the construction of this Plan.
7 EXHIBIT 10.10 Page 7 of 7
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statement on Form S-8 (No. 333-98379)of Berry Petroleum Company
of our report dated February 12, 2003 relating to the financial
statements, which appears in the Annual Report to Shareholders,
which is incorporated in this Annual Report on Form 10-K.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
March 10, 2003
Los Angeles, California
EXHIBIT 23.1
February 27, 2003
Berry Petroleum Company
5201 Truxtun Avenue, Suite 300
Bakersfield, California 93309
Gentlemen:
In connection with the Annual Report on Form 10-K for the
fiscal year ended December 31, 2002, (the Annual Report) of Berry
Petroleum Company (the Company), we hereby consent to (i) the use
of and reference to our report dated February 14, 2003, entitled
"Appraisal Report, as of December 31, 2002, on Certain Property
Interests owned by Berry Petroleum Company," which pertains to
interests of the Company in certain oil and gas properties
located in California, Louisiana, Nevada, Oklahoma, Texas, and
Wyoming; our report dated February 25, 2002, entitled "Appraisal
Report, as of December 31, 2001, on Certain Property Interests
owned by Berry Petroleum Company," which pertains to interests of
the Company in certain oil and gas properties located in
California, Louisiana, Nevada, Oklahoma, Texas, and Wyoming; our
report dated February 26, 2001, entitled "Appraisal Report, as of
December 31, 2000, on Certain Property Interests owned by Berry
Petroleum Company," which pertains to interests of the Company in
certain oil and gas properties located in California, Louisiana,
Nevada, Oklahoma, Texas, and Wyoming (collectively referred to as
the "Reports"), under the caption "Oil and Gas Reserves" in items
1 and 2 of the Annual Report and under the caption "Supplemental
Information About Oil and Gas Producing Activities (Unaudited)"
in item 8 of the Annual Report; and (ii) the use of and reference
to the name DeGolyer and MacNaughton as the independent petroleum
engineering firm that prepared the Reports under such items;
provided, however, that since the cash-flow calculations in the
Annual Report include estimated income taxes not included in the
Reports, we are unable to verify the accuracy of the cash-flow
values in the Annual Report.
Very truly yours,
DeGOLYER and MacNAUGHTON
EXHIBIT 23.2
UNDERTAKING FOR FORM S-8 REGISTRATION STATEMENT
For purposes of complying with the amendments to the rules
governing Form S-8 (effective July 13, 1990) under the Securities
Act of 1933, the Company hereby undertakes as follows, which
undertaking shall be incorporated by reference into the Company's
Registration Statement on Form S-8 (No. 333-98379):
Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to director, officers and
controlling persons of the Company pursuant to the foregoing
provisions, or otherwise, the Company has been advised that in
the opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed in the
Securities Act of 1933 and is, therefore, unenforceable. In the
event that a claim for indemnification against such liabilities
(other than the payment by the Company of expenses incurred or
paid by a director, officer or controlling person of the Company
in the successful defense of any action, suit or proceeding is
asserted by such director, officer or controlling person in
connection with the securities being registered, the Company
will, unless in the opinion of its counsel the matter has been
settled by controlling precedent, submit to a court of
appropriate jurisdiction the question whether such
indemnification is against public policy as expressed in the Act
and will be governed by the final adjudication of such issue.
Exhibit 99.1
Certification of CEO Pursuant to
18 U.S.C. Section 1350,
As Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the Annual Report of Berry Petroleum Company
(the "Company") on Form 10-K for the period ending December 31,
2002 as filed with the Securities and Exchange Commission on
March 11, 2003 (the "Report"), Jerry V. Hoffman, as Chairman,
President and Chief Executive Officer of the Company, hereby
certifies, pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the
best of his knowledge, that:
(1) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in
all material respects, the financial condition and result of
operations of the Company.
/s/ Jerry V. Hoffman
Jerry V. Hoffman
Chairman, President and Chief Executive Officer
March 11, 2003
This certification accompanies this Report pursuant to Section
906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed
filed by the Company for purposes of Section 18 of the Securities
Exchange Act of 1934, as amended.
Exhibit 99.4
Certification of CFO Pursuant to
18 U.S.C. Section 1350,
As Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the Annual Report of Berry Petroleum Company
(the "Company") on Form 10-K for the period ending December 31,
2002 as filed with the Securities and Exchange Commission on
March 11, 2003 (the "Report"), Ralph J. Goehring, Senior Vice
President and Chief Financial Officer of the Company, hereby
certifies, pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the
best of his knowledge, that:
(1) The Report fully complies with the requirements of section
13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in
all material respects, the financial condition and result of
operations of the Company.
/s/ Ralph J. Goehring
Ralph J. Goehring
Senior Vice President and Chief Financial Officer
March 11, 2003
This certification accompanies this Report pursuant to Section
906 of the Sarbanes-Oxley Act of 2002 and shall not be deemed
filed by the Company for purposes of Section 18 of the Securities
Exchange Act of 1934, as amended.
Exhibit 99.5