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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 1997
Commission file number 1-9735
BERRY PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 77-0079387
(State of incorporation or organization)(I.R.S. Employer Identification Number)
28700 Hovey Hills Road
Taft, California 93268
(Address of principal executive offices, including zip code)
Registrant's telephone number, including area code: (805) 769-8811
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Class A Common Stock, $.01 par value New York Stock Exchange
(including associated stock purchase rights)
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90
days. YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [ ]
As of February 20, 1998, the registrant had 21,101,720 shares of
Class A Common Stock outstanding and the aggregate market value of the
voting stock held by nonaffiliates was approximately $225,744,000.
This calculation is based on the closing price of the shares on the New
York Stock Exchange on February 20, 1998 of $16.125. The registrant
also had 898,892 shares of Class B Stock outstanding on February 20,
1998, 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.
2
BERRY PETROLEUM COMPANY
TABLE OF CONTENTS
PART I
Items 1
and 2. Business and Properties . . . . . . . . . . . . . . . . . . . 3
General . . . . . . . . . . . . . . . . . . . . . . . . 3
Oil Marketing . . . . . . . . . . . . . . . . . . . . . 4
Steaming Operations . . . . . . . . . . . . . . . . . . 4
Environmental and Other Regulations . . . . . . . . . . 5
Competition . . . . . . . . . . . . . . . . . . . . . . 6
Employees . . . . . . . . . . . . . . . . . . . . . . . 6
Divestiture of Properties . . . . . . . . . . . . . . . 6
Oil and Gas Properties. . . . . . . . . . . . . . . . . 6
Development . . . . . . . . . . . . . . . . . . . . 6
Exploration . . . . . . . . . . . . . . . . . . . . 8
Enhanced Oil Recovery Tax Credits . . . . . . . . . . . 8
Oil and Gas Reserves . . . . . . . . . . . . . . . . . 8
Production . . . . . . . . . . . . . . . . . . . . . . 8
Acreage and Wells . . . . . . . . . . . . . . . . . . . 9
Drilling Activity . . . . . . . . . . . . . . . . . . . 9
Title and Insurance . . . . . . . . . . . . . . . . . . 9
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . 10
Item 4. Submission of Matters to a Vote of Security Holders. . . . 10
Executive Officers. . . . . . . . . . . . . . . . . . . 11
PART II
Item 5. Market for the Registrant's Common Equity and Related
Shareholder Matters . . . . . . . . . . . . . . . . . . 12
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . 13
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . 14
Item 8. Financial Statements and Supplementary Data . . . . . . . 18
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . . 37
PART III
Item 10. Directors and Executive Officers of the Registrant . . . . 37
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . 37
Item 12. Security Ownership of Certain Beneficial
Owners and Management . . . . . . . . . . . . . . . . . 37
Item 13. Certain Relationships and Related Transactions . . . . . . 37
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . 37
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PART I
Items 1 and 2. Business and Properties
General
Berry Petroleum Company, ("Berry" or "Company"), is an independent
energy company engaged in the production, development, acquisition,
exploitation, exploration and marketing of crude oil and natural gas.
The Company was incorporated in Delaware in 1985 and has been a
publicly traded company since 1987. Berry's principal reserves and
producing properties are located in Kern 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, 1997.
The Company's corporate headquarters are located on its properties in
the South Midway-Sunset field, near Taft, California and Management
believes the current facilities are adequate.
The Company's mission is to increase shareholder wealth, primarily
through maximizing the value and cash flow of the Company's assets. To
achieve this, Berry's corporate strategy is to remain a low cost
producer and to grow the Company's asset base strategically. To
increase production, the Company will compete to acquire primarily
proved reserves with exploitation potential and will focus on the
further development of its existing properties by application of
enhanced oil recovery (EOR) methods, developmental drilling, well
completions and remedial work. Berry believes that its primary strengths
are its ability to maintain a low cost operation and its flexibility in
acquiring attractive producing properties which have significant
exploitation and enhancement potential. While the Company is not currently
involved in exploration activities, the Company may investigate and pursue a
focused exploration program in the future. The Company has substantial
unused borrowing capacity to finance acquisitions and will consider, as
appropriate, the issuance of capital stock to finance future purchases.
Proved Reserves
As of December 31, 1997, the Company's estimated proved reserves
were 101 million barrels of oil equivalent, (BOE), of which 99.4% is
crude oil. The majority of these proved reserves are owned in fee.
Substantially all of the Company's reserves are located in California
with 94.4% and 5.5% of total reserves in Kern and Ventura Counties,
respectively. The Company's reserves have a long life, in excess of 20
years, which is primarily a result of the Company's strong position in
heavy crude oil (the Company's properties in the Midway-Sunset field
average 13 degree API gravity and the Montalvo field averages 16 degree
API gravity). Production in 1997 was 4.6 million BOE, up 28% from 1996
production of 3.6 million BOE. For the five years 1993 through 1997,
the Company's average reserve replacement rate was 245% at a cost of
$2.81 per BOE.
Operations
The Midway-Sunset field contains predominantly heavy crude oil,
the production of which depends substantially on steam injection.
Berry utilizes primary and cyclic steaming recovery methods in this
field and utilizes primary recovery methods at its Montalvo field.
Berry operates all of its principal oil producing properties. 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
transferred into crude oil pipelines owned by other companies. The
point-of-sale is usually at the LACT unit.
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4
Revenues
The percentage of revenues by source for the prior three years is
as follows:
1997 1996 1995
------ ------ ------
Sales of oil and gas 97% 97% 89%
Interest and other income 3% 3% 11%
Oil Marketing
The market for hydrocarbons continues to be quite volatile.
California crude oil pricing fundamentals have improved since Alaska
North Slope crude oil became available for export in mid-1996, and
because of declining Alaska production. These combined factors are
contributing to the reduction of the excess crude supply in the
California market, thus strengthening California prices relative to
West Texas Intermediate (WTI) prices. Although the spread has widened
in recent months, over the last several years California heavy crude
oil prices have increased as a percentage of WTI, from approximately
60% in 1990 to approximately 75% in both 1996 and 1997. Furthermore, a
strengthened California economy is providing for increased petroleum
product demand while, at the same time, past refinery investments have
resulted in higher demand for the heavy barrel. The California
downstream sector (refineries) has recently been involved in mergers,
combinations, or realignments, and the impact on producers' prices is
unknown at this time. Refinery upsets (fires, explosions, extended
turnarounds, etc.) can impact local crude prices, for limited times, by
weakening crude demand. Principally, as a result of large investments
required by the refinery industry in California to meet product
specifications and clean air regulations, the number of refineries has
decreased. Average refinery utilization has increased from
approximately 75% to 95% over the past decade and, therefore, any
individual refinery disruption has a more pronounced impact on
downstream crude oil demand.
The Company may enter into crude oil or natural gas hedge
contracts depending upon various factors including Management's view of
future crude oil markets. Berry's 1997 average heavy crude oil sales
price per barrel was $14.70, down $.72 per barrel, or 5%, from $15.42
in 1996 (both years are net of any hedging). The Company currently has
a hedge contract for 3,000 barrels per day (B/D) with a California
independent refiner which expires on August 31, 1998.
Management of the Company does not believe that the loss of any
single customer or contract would materially affect its business.
There are no significant delivery commitments and substantially all of
the Company's oil and gas production is sold under short-term contracts
at current market prices.
Steaming Operations
Approximately 94% of the Company's proved reserves, or 95 million
barrels, consist of heavy crude oil produced from depths less than
2000'. This heavy crude oil requires heat in the form of steam to be
injected into the oil producing formations to reduce the oil viscosity
and allow the oil to flow to the well-bore for production. As is
typical in EOR operations, steam represents the highest cost component
of operating expenses. The Company, in achieving its goal of being a
low cost heavy oil producer, has focused on reducing its steam cost by
the purchase of two gas-fired cogeneration facilities in 1995 and 1996.
Steam generation from these facilities is more efficient than
conventional steam generators, as both steam and electricity are
produced from the same natural gas fuel supply. Another significant
benefit is that the prices received upon the sale of electricity are
currently based on natural gas prices. As natural gas prices fluctuate,
so does the electricity revenue; thus, the Company's steam cost is
substantially hedged against higher natural gas prices. As the California
electric industry deregulates, this relationship will change and electricity
revenues will be impacted by other factors in addition to natural gas prices
and, consequently, the Company's steam costs will be more volatile.
Proceeds received from the sale of electricity produced by the Company's
cogeneration facilities are reported as a reduction in operating costs.
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5
For its South Midway-Sunset properties, the Company's current
steam production is generated by its 38 and 18 megawatt cogeneration
facilities (approximately 18,500 barrels of steam per day (BSPD)) and,
as needed, from conventional steam generators. In addition, the
Company made modifications to use the duct-firing capability of its 38
megawatt facility to produce up to an additional 4,500 BSPD available
for delivery to its South Midway-Sunset properties. Conventional steam
generation is used by the Company at its South Midway-Sunset properties
only as required to maintain current production levels, when additional
steam injection is expected to economically produce additional crude oil
and as emergency back-up steam generation to the cogeneration facilities.
On its North Midway-Sunset properties, the Company relies solely on
conventional steam generators for its steam requirements. The Company
has ample productive steam capacity for its requirements at both core areas.
Current oil prices, near-term oil price expectations and natural gas prices
are the primary factors determining steam levels generated from conventional
generators. Due to low oil prices occurring in early 1998, the Company
temporarily has shut down the duct-firing steam capacity and all conventional
steam generators at South Midway-Sunset to reduce costs and improve cash flow.
The Company's two cogeneration facilities sold electricity to a
large California-based utility under Standard Offer #2 (SO2) contracts
in 1996. The SO2 contract for the 38 megawatt facility expired on
January 16, 1997, while the contract for the 18 megawatt facility does
not expire until January 31, 2002. The SO2 contract for the 38
megawatt facility has been replaced by a 15-year Standard Offer #1
(SO1) contract effective January 16, 1997, which resulted in lower
electricity revenues for the 38 megawatt facility. However, under the
SO1 contract, the Company will continue to receive Short Run Avoided
Cost pricing plus a portion of the proceeds related to available
capacity that were received in prior years. Deregulation of the
electricity generation market in California may have a positive or
negative impact on the Company's future electricity revenues, however,
the Company believes, at a minimum, that continued steam generation
from cogeneration facilities will be significantly more efficient and
cost effective than conventional steam generation.
The Company has physical access to gas pipelines, such as the Kern
River/El Paso and Southern California Gas Company systems, to transport
its gas purchases required for steam generation. Prior to February
1997, natural gas purchases for the 38 megawatt cogeneration facility
were subject to a long-term gas transportation agreement which required
the Company to pay above-market transportation rates for a substantial
portion of the facility's gas requirements. However, this contract
expired and, as a result, the Company experienced substantial
reductions in its gas transportation costs beginning in 1997.
Environmental and Other Regulations
The operations of Berry are affected by federal, state, regional
and local laws and regulations, including laws governing allowable
rates of production, well spacing, air emissions, water discharges,
endangered species, marketing, pricing, taxes and other laws relating
to the petroleum industry. Berry is further affected by changes in
such laws and by constantly changing administrative regulations.
The Company's oil and gas operations and properties are subject to
numerous federal, state and local laws and regulations relating to
environmental protection. These laws and regulations govern, among
other things, the amounts and types of substances and materials that
may be released into the environment, the issuance of permits in
connection with drilling and production activities, the discharge and
disposition of waste materials, the reclamation and abandonment of
wells and facility sites and the remediation of contaminated sites. In
addition, these laws and regulations may impose substantial liabilities for
the Company's failure to comply with them or for any contamination resulting
from the Company's operations.
Berry has established policies and procedures for continuing
compliance with environmental laws and regulations affecting its
production. The costs incurred to comply with these laws and
regulations are inextricably connected to normal operating expenses
such that the Company is unable to separate the expenses related to
environmental matters; however, the Company does not believe any such
additional future expenses are material to its financial position or
results of operations.
5
6
Although environmental requirements do have a substantial impact
upon the energy industry, generally these requirements do not appear to
affect the Company any differently, or to any greater or lesser extent,
than other companies in California and in the domestic industry as a
whole. Berry believes that compliance with environmental laws and
regulations will not have a material adverse effect on the Company's
operations or financial condition but there can be no assurances that
changes in or additions to laws or regulations regarding the protection
of the environment will not have such an impact in the future.
Berry maintains insurance coverage which it believes is customary
in the industry, although it is not fully insured against all
environmental risks. The Company is not aware of any environmental
claims existing as of December 31, 1997, which would have a material
impact upon the Company's financial position or results of operations.
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
since integrated companies, 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 it is in a
position to compete effectively due to its low cost structure, transaction
flexibility, strong financial position and experience.
Employees
On December 31, 1997, the Company had 99 full-time employees.
Divestiture of Properties
In 1997, the Company sold its non-operated interests in Louisiana
and its California San Joaquin Valley "Eastside" properties for a
combined total of $1.5 million, and recorded a pre-tax gain of $.8
million. On the sale date, the Company had recorded reserves of 26,000
BOE associated with these properties. The Company disposed of these
properties due to limited exploitation potential and high operating
costs.
Oil and Gas Properties
Development
South Midway-Sunset - Berry owns and operates working interests in
eighteen properties consisting of 1,730 acres located in the South
Midway-Sunset field. The Company estimates these properties account
for approximately 82% of the Company's proved oil and gas reserves and
approximately 86% of its current daily production. Twelve of these
properties are owned in fee. The wells produce from an average depth
of approximately 1200'. These properties rely on thermal EOR methods,
primarily cyclic steaming.
During 1997, the primary focus on this field was directed at the
integration of the recently acquired Formax and Tannehill properties
into the Company's operations. Of the 76 new wells drilled in 1997 in
this area, 54 were drilled on these newly acquired properties. In
addition, during 1996 and 1997, the Company drilled a total of 4
horizontal wells in this field. The Company's objectives related to
using this developing technology were to improve ultimate recovery of
original oil-in-place, reduce the development and operating costs of
the properties and accelerate production. The Company has obtained
favorable results to date from these wells with current production of
approximately 81 B/D each. With the drilling of these wells and the
remedial work and workovers completed on 70 existing wells, the Company
increased production approximately 36% during 1997 to 10,428 B/D.
Included in the 1996 purchase of the Tannehill properties was the 18
megawatt cogeneration facility which has provided the Company with an
additional 5,500 B/D of low cost steam used in its thermal EOR process.
In 1998, the Company plans to drill an additional 42 development wells
in this field, 5 of which will be horizontal wells.
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7
North Midway-Sunset - Berry owns and operates approximately 1,975
acres in the North Midway-Sunset field which account for approximately
9% of the Company's proved oil and gas reserves and 8% of daily
production. These properties also rely on thermally enhanced oil
recovery methods, primarily cyclic steaming. Berry's interests consist
of four fee properties comprising 1,009 acres and eight leases
comprising 966 acres. The wells produce from an average depth of
approximately 1200'.
During 1997, the Company drilled 13 development wells to maintain
productive capacity and develop proved reserves. During 1998, the
Company plans to drill an additional 20 development wells in this area.
In addition, the Company has budgeted 3 intermediate depth exploitation
wells to evaluate the Antelope Shale and other diatomaceous shale
intervals.
Montalvo - Berry owns 100% working interest in six leases in
Ventura County, California in the Montalvo field. The State of
California is the lessor for two of the six leases. The Company
estimates current proved reserves from Montalvo account for
approximately 6% of Berry's proved oil and gas reserves. Total
production from these leases, comprised of 8,563 acres, represents
approximately 6% of Berry's total current daily oil and gas production.
The wells produce from an average depth of approximately 12,500'. No
new wells were drilled in 1997 or 1996.
The following is a summary of capital expenditures incurred during
1997 and 1996 and projected capital expenditures for 1998:
CAPITAL EXPENDITURES SUMMARY
(in thousands)
1998(1) 1997 1996(2)
--------- --------- ---------
(Projected)
South Midway-Sunset Field
New wells $ 5,095 $ 10,078 $ 4,099
Remedials/workovers 1,070 1,695 499
Facilities 1,620 3,180 317
Cogeneration facilities - 208 1,134
------ ------ ------
7,785 15,161 6,049
------ ------ ------
North Midway-Sunset Field
New wells 3,980 1,719 936
Remedials/workovers 130 251 213
Facilities 495 336 124
------ ------ ------
4,605 2,306 1,273
------ ------ ------
Other 1,087 1,130 1,911
------ ------ ------
Totals $ 13,477 $ 18,597 $ 9,233
====== ====== ======
(1) Budgeted capital expenditures may be adjusted for numerous reasons
including, but not limited to, results of drilling and oil price
levels. See the Future Developments section of Item 7. Management's
Discussion and Analysis of Financial Condition and Results of
Operations.
(2) Excludes the acquisition of properties and the 18 megawatt
cogeneration facility from Tannehill Electric Company.
7
8
Exploration
The Company did not participate in the drilling of any exploratory
wells in 1997 or 1996 and has none budgeted in 1998. Although the
Company has significantly reduced its exploration program since 1994 to
concentrate on growth through development of existing assets and
strategic acquisitions, as well as through improving profitability, the
Company may investigate and pursue a focused exploration program in the
future.
Enhanced Oil Recovery Tax Credits
In 1990, President Bush signed into law the Revenue Reconciliation
Act of 1990 which included a tax credit for certain costs associated
with extracting high-cost marginal oil which utilizes at least one of
nine designated "enhanced" or tertiary recovery methods. Cyclic steam
and steam drive recovery methods, which Berry utilizes extensively, are
qualifying EOR methods. Hydrocarbons produced from primary or other
secondary recovery methods are not eligible for the credit. 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 by investing in a qualified EOR project
which includes three distinct costs: (1) drilling new wells, (2)
adding facilities that are integrally related to qualified production,
and (3) utilizing a tertiary injectant, such as steam, to produce oil.
This credit is significant in reducing the Company's income tax
liabilities and effective tax rate.
Oil and Gas Reserves
Reserve Reports - 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 three years ended December 31, 1997 for all of the Company's
properties. 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 provided by the Company
considered applicable to each reserve report. 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, 1997. For the Company's operated
properties, these reserve estimates are filed annually with the U.S.
Department of Energy. Refer to the Supplemental Information About Oil
& Gas Producing Activities (Unaudited) for the Company's oil and gas
reserve disclosures.
Production
The following table sets forth certain information regarding
production for the years ended December 31, as indicated:
1997 1996 1995
Net annual production(1): ------ ------ ------
Oil (Mbbls) 4,503 3,491 3,277
Gas (Mmcf) 282 491 611
Total equivalent barrels(2) 4,550 3,573 3,379
Average sales price:
Oil (per bbl) $ 14.70 $ 15.42 $ 13.56
Gas (per mcf) 2.68 1.99 1.50
Per BOE 14.71 15.36 13.48
Average production cost (per BOE) 4.92 4.92 5.41
(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.
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Acreage and Wells
At December 31, 1997, the Company's properties accounted for the
following developed and undeveloped acres:
Developed Acres Undeveloped Acres
--------------- -----------------
Gross Net Gross Net
----- ----- ----- -----
California 6,293 6,292 6,846 6,846
Other 1,010 174 - -
------ ------ ------ ------
7,303 6,466 6,846 6,846
====== ====== ====== ======
Gross acres represent all acres in which Berry has a working
interest; net acres represent Berry's aggregate working interests in
the gross acres.
Berry currently has 2,048 gross oil wells (2,037 net) and 5 gross
gas wells (3.3 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:
1997 1996 1995
-------------- ------------- -------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Exploratory wells drilled:
Productive 0 0.0 0 0.0 0 0.0
Dry(1) 0 0.0 0 0.0 4 0.7
Development wells drilled:
Productive 89 88.9 46 45.1 44 44.0
Dry(1) 1 1 3 2.1 1 1.0
Total wells drilled:
Productive 89 88.9 46 45.1 44 44.0
Dry(1) 1 1 3 2.1 5 1.7
(1) A dry well is a well found to be incapable of producing either oil
or gas in sufficient quantities to justify completion as an oil or gas
well
Title and Insurance
The Company is not aware of any defect in the title to any of its
principal properties. Notwithstanding the absence of a recent title
opinion or title insurance policy, the Company believes it has
satisfactory title to these 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. Title insurance was obtained by the
Company on the Tannehill and Formax properties upon their acquisition
in 1996.
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 the oil and gas
business.
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Item 3. Legal Proceedings
In 1993, the Company incurred an oil spill on its Montalvo
properties. In early 1997, the Company reached a final settlement with
the appropriate federal and state agencies. Management believes that
its prior accruals have been adequate and that any remaining charges or
income will be immaterial to the Company.
The Company is a party to certain lawsuits arising in the ordinary
course of business. Although the outcome of these lawsuits cannot be
predicted with certainty, the Company does not expect such matters to
have a material adverse effect on the financial statements of the
Company.
Item 4. Submission of Matters to a Vote of Security Holders
None.
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EXECUTIVE OFFICERS
Listed below are the names, ages (as of December 31, 1997) 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 elected in May of each year at an organizational meeting of
the Board of Directors. There are no family relationships between any
executive officers and members of the Board of Directors.
JERRY V. HOFFMAN, 48, 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 on March 21, 1997. Mr.
Hoffman held the Senior Vice President and Chief Financial Officer
positions from January 1988 until March 1992. Mr. Hoffman, a CPA, has
held a variety of other positions with the Company and its predecessors
since February 1985.
DONALD A. DALE, 51, Controller since December 1985. Mr. Dale, a
CPA, was the Controller for Berry Holding Company from September 1985
to December 1985.
RALPH J. GOEHRING, 41, 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, a CPA, is also the
Assistant Secretary for Berry Petroleum Company.
KENNETH A. OLSON, 42, Corporate Secretary since December 1985 and
Treasurer since August 1988. Mr. Olson, a CPA, has held a variety of
other positions with the Company and its predecessors since July 1985.
BRIAN L. REHKOPF, 50, Manager of Engineering since September 1997,
joined the Company's engineering department in June 1997. Mr. Rehkopf,
a registered petroleum engineer, was previously a Vice President and
Asset Manager with ARCO Western Energy, a subsidiary of Atlantic
Richfield Corp. (ARCO) since 1992 and an Operations Engineering
Supervisor with ARCO from 1988 to 1992.
MICHAEL R. STARZER, 36, Vice President of Corporate Development
since March 1996 and Manager of Corporate Development since April 1995.
Mr. Starzer, a registered petroleum engineer, was with Unocal from
August 1983 to May 1991 and from August 1993 to April 1995. Mr.
Starzer was an engineering consultant and worked with the California
State Lands Commission from May 1991 to August 1993.
STEVEN J. THOMAS, 47, passed away February 21, 1998. Mr. Thomas
was Manager of Production from March 1993 until his death. Mr. Thomas
joined the Company's engineering department in September 1992. Mr.
Thomas, a registered petroleum engineer, was an engineering and
petroleum consultant from 1990 to 1992 and was employed by
Chevron USA from 1979 to 1990 in various drilling, production and
facilities engineering positions.
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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 1989, 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 22, 1989. Each share of Capital
Stock issued after December 22, 1989 includes one Right. The Rights
expire on December 8, 1999. See Note 7 of Notes to the Financial
Statements.
In conjunction with the acquisition of Tannehill in 1996, the
Company issued a Warrant Certificate to the beneficial owners of
Tannehill Oil Company. This Warrant authorizes the purchase of 100,000
shares of Berry Petroleum Company Class A Common Stock until November
8, 2003 at $14.06 per share. All the warrants are currently
outstanding and the underlying shares will not be registered under the
Securities Act of 1933.
Berry's Class A Common Stock is listed on the New York Stock
Exchange under the symbol "BRY". The Class B Stock is not publicly
traded. The market data and dividends for 1997 and 1996 are shown
below:
1997 1996
--------------------------- -----------------------------
Price Range Dividends Price Range Dividends
High Low per Share High Low per Share
-------- ------ --------- -------- ------ ---------
First Quarter $ 15 7/8 $ 14 $ .10 $ 11 1/8 $ 8 3/4 $ .10
Second Quarter 19 13 7/8 .10 12 1/2 10 3/8 .10
Third Quarter 20 1/2 16 3/16 .10 11 3/4 10 3/8 .10
Fourth Quarter 21 3/8 17 .10 14 1/2 11 1/4 .10
The closing price per share of Berry's Common Stock, as reported
on the New York Stock Exchange Composite Transaction Reporting System
for February 20, 1998, December 31, 1997 and December 31, 1996 was
$16.125, $17.4375 and $14.375, respectively.
The number of holders of record of the Company's Common Stock was
926 (and approximately 3,000 street name shareholders) as of February
20, 1998. There was one Class B Stockholder of record as of February
20, 1998.
The Company paid cash dividends for many years prior to the
roll-up of the various Berry companies into Berry Petroleum Company on
December 16, 1985. Since Berry's formation, the Company has
paid dividends on its Common Stock for eight consecutive semi-annual
periods through September 1989 and for 33 consecutive quarters
through December 31, 1997. 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
and other relevant factors.
At December 31, 1997, dividends declared on 4,041,400 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.
12
13
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, 1997 were
derived from the audited financial statements and the accompanying
notes to those financial statements (in thousands, except per share and
per barrel data):
1997 1996 1995 1994 1993
Statement of Operations ------ ------ ------ ------ ------
Data:
Sales of oil and gas $ 67,172 $ 55,264 $ 45,773 $ 39,451 $ 42,843
Operating costs 22,407 17,587 18,264 21,224 23,790
General and administrative
expenses (G&A) 5,907 4,820 4,578 5,118 5,999
Depreciation, depletion
& amortization(DD&A) 10,138 7,323 6,847 7,270 9,983
Net income (loss) 19,260 17,546 12,203 (1,129) 32
Basic net income (loss)
per share .88 .80 .56 (.05) -
Weighted average number
of shares outstanding 21,976 21,939 21,932 21,932 21,926
Balance Sheet Data:
Working capital $ 11,499 $ 7,850 $ 36,506 $ 38,273 $ 40,418
Total assets 177,724 176,403 117,722 118,254 135,519
Long-term debt 32,000 36,000 - - -
Shareholders' equity 111,871 101,009 92,060 88,632 98,323
Cash dividends
per share .40 .40 .40 .40 .55
Operating Data:
Cash flow from
operations 31,401 29,182 17,070 14,579 10,957
Capital expenditures
(excluding acquisitions)18,597 15,616 14,569 5,911 13,983
Property acquisitions - 69,330 503 1,023 -
Per BOE:
Sales price $ 14.71 $ 15.36 $ 13.48 $ 11.60 $ 11.43
Operating costs 4.92 4.92 5.41 6.28 6.35
G&A 1.30 1.35 1.35 1.51 1.60
------- ------- ------- ------- -------
Cash flow 8.49 9.09 6.72 3.81 3.48
DD&A 2.23 2.05 2.03 2.15 2.67
------- ------- ------- ------- -------
Operating income $ 6.26 $ 7.04 $ 4.69 $ 1.66 $ .81
======= ======= ======= ======= =======
Production (BOE) 4,550 3,573 3,379 3,382 3,746
Proved Reserves Information:
Total BOE 101,043 102,116 78,068 77,084 72,991
Present value (PV10) of
estimated future cash
flow before
income taxes $376,459 $634,579 $308,370 $263,890 $ 50,124
Year end BOE price for
PV10 purposes 12.19 18.37 13.39 12.49 8.25
Other:
Return on average
shareholders' equity 18.1% 18.2% 13.6% (1.2)% 0%
Return on average total
assets 10.9% 13.3% 10.5% (0.9)% 0%
Total debt/total debt
plus equity 22.2% 29.8% N/A N/A N/A
13
14
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, 1997 and the
financial condition, liquidity and capital resources as of December 31,
1997. 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 and gas sold, the type and volume of oil and gas produced
and the results of acquisition, development, exploitation and
exploration activities. The average realized prices for oil and gas
will fluctuate from one period to another due to world and regional
market conditions and other factors. 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. Production rates, steam costs, labor, maintenance expenses
and production taxes are expected to be the principal influences on
operating costs. Accordingly, the results of operations of the Company
may fluctuate from period to period based on the foregoing principal
factors, among others.
Results of Operations
Net income for 1997 was $19.3 million, up 10%, or $1.8 million,
from $17.5 million in 1996 and 58%, or $7.1 million, from $12.2 million
in 1995. For the fourth quarter of 1997, net income was $4.7 million,
down 11% from $5.3 million in the fourth quarter of 1996, but up 27%
from $3.7 million in the fourth quarter of 1995. Although production
on the Company's core assets has continued to increase, profitability
decreased from the third quarter of 1997 due to lower oil prices and
higher operating costs.
The following table presents certain operating data for the years
ended December 31, 1997, 1996 and 1995 for comparative purposes:
1997 1996 1995
---- ---- ----
Net production - BOE per day 12,465 9,762 9,258
Per BOE:
Average sales price $14.71 $15.36 $13.48
Operating costs* 4.24 4.44 4.96
Production taxes 0.68 0.48 0.45
Total operating costs 4.92 4.92 5.41
DD&A 2.23 2.05 2.03
G&A 1.30 1.35 1.35
* Excluding production taxes.
Operating income from producing operations was $35.0 million in
1997, up $4.3 million from $30.7 million in 1996 and up $15.9 million
from $19.1 million in 1995. The improvement from 1996 was primarily
due to higher production volumes, partially offset by both higher DD&A
and production taxes, and lower oil prices.
The average sales price/BOE received of $14.71 in 1997 was 4%
lower than the $15.36 received in 1996, but 9% higher than the $13.48
received in 1995. Recently, worldwide oil prices have declined sharply
with average postings for Midway-Sunset field crude oil at $7.13 per
barrel as of March 9, 1998. Oil and gas production was 12,465 BOE/day,
up 28% from 9,762 BOE/day in 1996 and up 35% from 9,258 BOE/day in 1995.
The increase in production was due primarily to the 1997 drilling and
development program and increased steam volumes related to the properties
acquired in the fourth quarter of 1996. Total production from the Formax
and Tannehill properties purchased in the fourth quarter of 1996 has
increased to approximately 3,900 BOE/day at the end of 1997 from
approximately 2,200 BOE/day upon acquisition.
14
15
The Company has a hedge contract for 3,000 B/D of the Company's
crude production with a California refiner to help protect the
Company's revenue from declines in the price of crude oil. The current
contract was initiated in February 1997 and expires on August 31, 1998.
The current price of California heavy crude oil is considerably under
the lower threshold of the contract, therefore, the Company anticipates
that its revenues per barrel will be beneficially impacted under the
terms of the contract, if the low price levels continue.
Operating costs per BOE in 1997 of $4.92 were equal to $4.92 in
1996 and 9% lower than $5.41 in 1995. The Formax properties were
produced by our predecessor at reservoir temperatures below the
temperature conditions on the Company's adjacent properties. To
improve production levels, the Company provided additional heat to the
reservoir by firing several conventional generators in addition to its
cogeneration facilities to increase the volume of injected steam.
However, the cost of conventionally generated steam is more expensive
than the steam produced by the Company's two cogeneration plants.
Therefore, the cost of steam and the volume injected increased in 1997
compared to 1996. On a per barrel basis, the Company more than offset
this increased steam cost by reducing other lifting costs.
Production taxes per BOE have increased $.20, or 42%, in 1997
compared to 1996 due primarily to the 1996 acquisitions and
significantly higher pricing assumptions used by Kern County to
calculate the 1997/1998 property taxes. The Company expects lower
production taxes in 1998, in both real terms and on a BOE basis,
primarily due to the current low oil price environment and higher
anticipated production. Although total operating costs increased, operating
costs/BOE were equal to the 1996 level due to higher production volumes
in 1997. The Company anticipates that its operating cost per BOE will
trend lower in 1998 due to increased production, lower production taxes
and continuing operating cost efficiencies.
DD&A per BOE increased to $2.23 in 1997, up from $2.05 and $2.03
in 1996 and 1995, respectively. The increase was due primarily to the
1996 property acquisitions and increased drilling activity in 1996 and
1997. The Company expects that its DD&A cost per BOE will stay
relatively flat to slightly higher in 1998.
In 1997, the Company completed the sale of its California San
Joaquin Valley "Eastside" non-core properties located in the Poso Creek
and Kern Front fields and certain non-operated interests in Louisiana
for a total of $1.5 million. The Company disposed of these properties
due to limited exploitation potential and high operating costs.
In the fourth quarter of 1996, the Company acquired the producing
properties of Tannehill Oil Company and Formax Oil Company, which are
adjacent to the Company's core South Midway-Sunset properties. At the
time of the acquisitions, the properties produced approximately 2,250
barrels per day of 13 degree API gravity crude oil. As of December 31,
1997, production from these properties had increased to approximately
3,900 B/D, exceeding the Company's stated goal of 3,500 B/D.
General
Interest and dividend income in 1997 was $.6 million, down from
$2.1 million and $2.0 million in 1996 and 1995, respectively. In
addition, interest expense for 1997 was $2.3 million, up significantly
from $.2 million in 1996 and $0 in 1995. The Company did not
capitalize any interest in 1997 or 1996. These fluctuations were due
to the use of cash and debt to finance the acquisitions made in the
fourth quarter of 1996. Total debt at December 31, 1996 was $42.9
million, comprised of long-term debt of $36 million and a short-term
note payable of $6.9 million. However, by the end of 1997, total debt
was $32 million, all long-term, for a total reduction of $10.9 million,
or 25%. The Company expects long-term debt to decrease further in 1998
unless additional capital is needed for an acquisition and/or the price
of crude oil remains low.
G&A was $5.9 million in 1997, up 23% and 28%, from $4.8 million in
1996 and $4.6 million in 1995, respectively. However, on a BOE basis,
G&A decreased to $1.30 from $1.35 in both 1996 and 1995. Two factors
that increased G&A costs in 1997 were higher non-cash compensation
related to the exercising of stock options and the writeoff of failed
acquisition expenses. These two items accounted for $.7 million. The
Company anticipates that its total G&A costs will not exceed its 1997
costs and will continue to decrease on a per BOE basis.
15
16
The Company's effective income tax rate in 1997 was 32%, down from
36% and 37% in 1996 and 1995, respectively. The lower rate in 1997 was
due to additional federal and state tax credits generated from increased
investment in qualified enhanced oil recovery projects. The Company
expects that its effective rate would decrease significantly in a
continuing low oil price environment.
In December 1997, the Company adopted Statement of Financial Accounting
Standards (SFAS) No. 128, "Earnings Per Share". As required by this
new standard, the Company reports two earnings per share amounts, basic
net income per share and diluted 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.
Also, during 1997 the Company adopted the provisions of the
American Institute of Certified Public Accountants Statement of
Position (SOP) 96-1, "Environmental Remediation Liabilities" and SFAS
No. 125, "Accounting for Transfer and Servicing of Financial Assets and
Extinguishments of Liabilities." The adoption of these two pronouncements
had no material impact on the financial statements of the Company.
During 1996, the Company implemented the disclosure requirements
of SFAS No. 123, "Accounting for Stock Based Compensation." This
statement sets forth alternative standards for recognition of the cost
of stock-based compensation and requires that a Company's financial
statements include certain disclosures about stock-based employee
compensation arrangements regardless of the method used to account for
them. As allowed in this statement, the Company continues to apply
Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock
Issued to Employees," and related interpretations in recording
compensation related to its plans. The supplemental disclosure
requirements and further information related to the Company's stock option
plans are presented in Note 9 to the Company's financial statements.
Financial Condition, Liquidity and Capital Resources
Working capital as of December 31, 1997 was $11.5 million, up from
$7.9 million at December 31, 1996, but down from $36.5 million at
December 31, 1995. Cash flow from operations in 1997 increased to a
record $31.4 million, up 8% and 84% from $29.2 million and $17.1
million in 1996 and 1995, respectively. Cash flow increased in 1997
from 1996 due primarily to higher production, offset partially by lower
oil prices. Working capital increased in 1997 primarily because
internally generated cash flow was more than sufficient to pay $18.6
million in capital expenditures, $8.8 million in dividends and retire
$10.9 million in debt, $6.9 million of which was short-term notes
payable. The Company drilled and completed 89 new wells in 1997,
reworked an additional 70 wells and made several improvements and
additions to surface facilities on the Company's core properties.
On December 1, 1996, the Company established a $150 million
unsecured three-year revolving credit facility with NationsBank of
Texas. As of December 31, 1997, the borrowing base was $40 million,
but was reduced to $35 million on January 23, 1998. The Company is
carrying $32 million in long-term debt under this credit facility as of
February 20, 1998.
The total proved reserves at December 31, 1997 were 101 million
BOE, down from 102.1 million BOE at December 31, 1996 and up from 78.1
million BOE at December 31, 1995. After production of 4.6 million BOE,
the Company's proved reserves increased 3.5 million BOE, or 76%, of
1997 production. The increase in 1996 was primarily related to the
acquisition of Tannehill and Formax in the fourth quarter of 1996. The
Company's present value of estimated future net cash flows before
income taxes, discounted at 10%, was $376 million at December 31, 1997,
down 41% from $635 million at December 31, 1996, but up 22% from $308
million at December 31, 1995. These values were determined based on
year end oil prices of $12.19, $18.37 and $13.39 per BOE for 1997, 1996
and 1995, respectively.
16
17
Future Developments
In December 1997, worldwide crude oil prices began to decline
sharply and, as of March 9, 1998, the current average posting for the
Company's 13 degree API gravity crude oil is $7.13 per barrel. In
response, the Company will defer a minimum of 25% of its original 1998
$13.4 million capital program until at least the latter part of 1998 or
until crude prices recover. In addition, certain operating costs have
been reduced, such as steam, contractor services and overhead in
response to the current pricing situation. Also, in mid-March 1998 the
Company is instituting a 10% across-the-board salary cut with certain
members of Management taking a larger percentage reduction.
Deregulation of the electricity generation market in California
may have a positive or negative impact on the Company's future steam
costs as electricity prices somewhat de-couple from natural gas prices.
Currently, the Company's electricity price received for sales from the
two cogeneration plants owned by the Company correlates directly with
natural gas prices. Therefore, our net steam costs are fairly consistent
between quarters and years. In the future, electricity prices will be
determined by not only the cost of natural gas, but also the cost of coal,
hydroelectric, nuclear and other sources of fuel. In addition, power
consumption demand may make electricity prices more volatile than in the past.
The Company has performed a review of its computer systems and
software to determine what steps must be taken to ensure the Company
can handle transactions in the year 2000 and beyond. To handle this
"Year 2000" issue, the Company will be replacing all of its accounting
software in 1998 and expects this project to be completed in a timely
manner for a total cost of approximately $.6 million. The Company is
assessing all other Company systems to verify that they are "Year 2000"
compliant.
In 1998, the Company will adopt SFAS No. 130, "Reporting
Comprehensive Income." Management does not believe that adoption of
this standard will have a material impact on the financial statements
of the Company.
Impact of Inflation
The impact of inflation on the Company has not been significant in
recent years because of the relatively low rates of inflation experienced
in the United States.
Forward Looking Statements
"Safe Harbor" statement 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 and gas,
environmental risks, drilling and operating risks, uncertainties about
the estimates of reserves and government regulation.
17
18
Item 8. Financial Statements and Supplementary Data
BERRY PETROLEUM COMPANY
Index to Financial Statements and
Supplementary Data
Page
Report of Coopers & Lybrand L.L.P., Independent Accountants . . . . . . 19
Balance Sheets at December 31, 1997 and 1996 . . . . . . . . . . . . . 20
Statements of Operations for the
Years Ended December 31, 1997, 1996 and 1995 . . . . . . . . . . . . 21
Statements of Shareholders' Equity for the
Years Ended December 31, 1997, 1996 and 1995 . . . . . . . . . . . . 22
Statements of Cash Flows for the
Years Ended December 31, 1997, 1996 and 1995 . . . . . . . . . . . . 23
Notes to the Financial Statements . . . . . . . . . . . . . . . . . . . 24
Supplemental Information About Oil & Gas Producing Activities . . . . . 35
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.
18
19
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
Berry Petroleum Company
We have audited the accompanying balance sheets of Berry Petroleum
Company as of December 31, 1997 and 1996, and the related statements of
operations, shareholders' equity and cash flows for each of the three
years in the period ended December 31, 1997. 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 in accordance with generally accepted auditing
standards. Those standards 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. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Berry
Petroleum Company as of December 31, 1997 and 1996, and the results of
its operations and its cash flows for each of the three years in the
period ended December 31, 1997, in conformity with generally accepted
accounting principles.
COOPERS & LYBRAND L.L.P.
/s/ Coopers & Lybrand L.L.P.
February 20, 1998
Los Angeles, California
19
20
BERRY PETROLEUM COMPANY
Balance Sheets
December 31, 1997 and 1996
(In Thousands, Except Share Information)
1997 1996
ASSETS ------- -------
Current assets:
Cash and cash equivalents $ 7,756 $ 9,970
Cash - restricted - 2,570
Short-term investments available for sale 718 704
Accounts receivable 8,990 11,701
Prepaid expenses and other 1,979 1,307
------- -------
Total current assets 19,443 26,252
Oil and gas properties (successful efforts
basis), buildings and equipment, net 157,441 149,510
Other assets 840 641
------- -------
$ 177,724 $ 176,403
======= =======
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 4,432 $ 5,154
Notes payable - 6,900
Accrued liabilities 2,459 5,300
Federal and state income taxes payable 1,053 1,048
------- -------
Total current liabilities 7,944 18,402
Long-term debt 32,000 36,000
Deferred income taxes 25,909 20,992
Shareholders' equity:
Preferred stock, $.01 par value, 2,000,000
shares authorized; no shares outstanding - -
Capital stock, $.01 par value:
Class A Common Stock, 50,000,000
shares authorized; 21,094,494 shares
issued and outstanding (21,046,885 in 1996) 211 210
Class B Stock, 1,500,000 shares authorized;
898,892 shares issued and outstanding
(liquidation preference of $899) 9 9
Capital in excess of par value 53,422 53,029
Retained earnings 58,229 47,761
------- -------
Total shareholders' equity 111,871 101,009
------- -------
$ 177,724 $ 176,403
======= =======
The accompanying notes are an integral part of these financial
statements.
20
21
BERRY PETROLEUM COMPANY
Statements of Operations
Years ended December 31, 1997, 1996 and 1995
(In Thousands, Except Per Share Data)
1997 1996 1995
------- ------- -------
Revenues:
Sales of oil and gas $ 67,172 $ 55,264 $ 45,773
Interest and dividend income 643 2,081 2,040
Gain on sale of assets 1,093 - 3,073
Other income (expense), net 87 (72) 304
------- ------- -------
68,995 57,273 51,190
------- ------- -------
Expenses:
Operating costs 22,407 17,587 18,264
Depreciation, depletion &
amortization 10,138 7,323 6,847
Interest expense 2,302 178 -
Exploratory dry hole costs - 71 2,012
General and administrative 5,907 4,820 4,578
------- ------- -------
40,754 29,979 31,701
------- ------- -------
Income before income taxes 28,241 27,294 19,489
Provision for income taxes 8,981 9,748 7,286
------- ------- -------
Net income $ 19,260 $ 17,546 $ 12,203
======= ======= =======
Basic net income per share $ .88 $ .80 $ .56
======= ======= =======
Diluted net income per share $ .87 $ .80 $ .56
======= ======= =======
Weighted average number of
shares of capital stock
outstanding (used to calculate
basic net income per share) 21,976 21,939 21,932
Effect of dilutive securities:
Stock options 173 25 -
Warrants 16 - -
------- ------- -------
Weighted average number of shares of
capital stock used to calculate
diluted net income per share 22,165 21,964 21,932
======= ======= =======
The accompanying notes are an integral part of these financial
statements.
21
22
BERRY PETROLEUM COMPANY
Statements of Shareholders' Equity
Years Ended December 31, 1997, 1996 and 1995
(In Thousands, Except Per Share Data)
Capital in
Capital Stock Excess of Retained Shareholders'
Class A Class B Par Value Earnings Equity
------- ------- ---------- -------- ------------
Balances at
January 1, 1995 $ 210 $ 9 $ 52,852 $ 35,561 $ 88,632
Stock options expired - - (2) - (2)
Cash dividends declared-
$.40 per share - - - (8,773) (8,773)
Net income - - - 12,203 12,203
----- ----- ------- ------- -------
Balances at
December 31, 1995 210 9 52,850 38,991 92,060
Stock retired - - (1) - (1)
Stock options exercised - - 180 - 180
Cash dividends declared-
$.40 per share - - - (8,776) (8,776)
Net income - - - 17,546 17,546
----- ----- ------- ------- -------
Balances at
December 31, 1996 210 9 53,029 47,761 101,009
Stock options
exercised 1 - 393 - 394
Cash dividends declared-
$.40 per share - - - (8,792) (8,792)
Net income - - - 19,260 19,260
----- ----- ------- ------- -------
Balances at
December 31, 1997 $ 211 $ 9 $ 53,422 $ 58,229 $ 111,871
===== ===== ======= ======= =======
The accompanying notes are an integral part of these financial
statements.
22
23
BERRY PETROLEUM COMPANY
Statements of Cash Flows
Years Ended December 31, 1997, 1996 and 1995
(In Thousands)
1997 1996 1995
Cash flows from operating activities: ------- ------- -------
Net income $ 19,260 $ 17,546 $ 12,203
Depreciation, depletion
and amortization 10,138 7,323 6,847
Gain on sale of assets (1,093) - (3,073)
Exploratory dry hole costs - 71 2,012
Increase (decrease) in deferred
income tax liability 4,917 4,024 (1,985)
Other, net (302) (329) (72)
------- ------- -------
Net working capital provided by
operating activities 32,920 28,635 15,932
Decrease (increase) in current assets
other than cash, cash equivalents
and short-term investments 2,039 (2,262) 3,113
Increase (decrease) in current
liabilities other than
notes payable (3,558) 2,809 (1,975)
------- ------- -------
Net cash provided by operating
activities 31,401 29,182 17,070
------- ------- -------
Cash flows from investing activities:
Capital expenditures, excluding
property acquisitions (18,597) (15,616) (14,569)
Property acquisitions - (69,330) (503)
Proceeds from sale of assets 1,892 352 6,242
Purchase of short-term investments (14) (710) (3,078)
Maturities of short-term investments - 15,700 15,000
Restricted cash deposit 2,570 (2,570) -
Other, net (50) (100) (96)
------- ------- -------
Net cash provided by (used in)
investing activities (14,199) (72,274) 2,996
------- ------- -------
Cash flows from financing activities:
Proceeds from issuance of
long-term debt 3,000 36,000 -
Proceeds from issuance of short-term
notes payable - 6,900 -
Payment of long-term debt (7,000) - -
Payment of short-term notes payable (6,900) - -
Dividends paid (8,792) (8,776) (8,773)
Proceeds from exercise of
stock options 276 179 -
------- ------- -------
Net cash provided by (used in)
financing activities (19,416) 34,303 (8,773)
------- ------- -------
Net increase (decrease) in cash and
cash equivalents (2,214) (8,789) 11,293
Cash and cash equivalents at
beginning of year 9,970 18,759 7,466
------- ------- -------
Cash and cash equivalents at
end of year $ 7,756 $ 9,970 $ 18,759
======= ======= =======
Supplemental disclosures of cash flow information:
Interest paid $ 2,319 $ - $ 12
======= ======= =======
Income taxes paid $ 4,280 $ 4,709 $ 5,554
======= ======= =======
The accompanying notes are an integral part of these financial
statements.
23
24
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
1. General
The Company is an independent energy company engaged in the
production, development, acquisition, exploitation, exploration and
marketing of crude oil and natural gas. Substantially all of the
Company's oil and gas reserves are located in California.
Approximately 99% of the Company's production is crude oil, which is
principally sold to other oil companies for processing in refineries
located in California.
The preparation of financial statements in conformity with
generally accepted accounting principles 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 amortized over the remaining life of the reserves using the units-
of-production method. Exploratory dry hole costs and other exploratory
costs, including geological and geophysical costs, are charged to
expense when incurred. The costs of carrying and retaining unproved
properties are also expensed when incurred.
Depletion of oil and gas producing properties is computed using
the units-of-production method. Depreciation of lease and well
equipment is computed using the units-of-production method or on a
straight-line basis over estimated useful lives ranging from 10 to 20
years. The estimated costs, net of salvage value, of plugging and
abandoning oil and gas wells and related facilities are accrued using
the units-of-production method and are taken into account in
determining DD&A expense. Buildings and equipment are recorded at
cost. Depreciation is provided on a straight-line basis over estimated
useful lives ranging from 5 to 30 years for buildings and improvements
and 3 to 10 years for machinery and equipment. Assets are grouped at
the field level and if it is determined that the book value of long-
lived assets cannot be recovered by estimated future undiscounted cash
flows, they will be 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.
24
25
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
2. Summary of significant accounting policies (cont'd)
Hedging
The Company periodically enters into bracketed zero cost collar
hedge contracts on a portion of its crude oil production with a
California refiner to protect the Company's revenues from potential
price declines. Any revenues received or costs incurred related to
this hedging activity is reflected in sales of oil and gas of the
Company.
Steam Costs
The costs of producing steam are recorded as an operating expense
of the Company. Proceeds received from the sale of electricity
produced by its cogeneration plants are reported as a reduction to
operating costs in the Company's financial statements.
Stock-Based Compensation
During 1996, the Company implemented the disclosure requirements
of Statement of Financial Accounting Standards (SFAS) No. 123,
"Accounting for Stock-Based Compensation." This statement sets forth
alternative standards for recognition of the cost of stock-based
compensation and requires that a Company's financial statements
include certain disclosures about stock-based employee compensation
arrangements regardless of the method used to account for them. As
allowed in this statement, the Company continues to apply Accounting
Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued to
Employees," and related interpretations in recording compensation
related to its plans. The supplemental disclosure requirements and
further information related to the Company's stock option plans are
presented in Note 9 to the Company's financial statements.
Income Taxes
Income taxes are provided based on the liability method of
accounting pursuant to SFAS No. 109, "Accounting for Income Taxes."
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 bases 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.
Earnings Per Share
In December 1997, the Company adopted SFAS No. 128, "Earnings per
Share." As required by this new standard, the Company reports two
earnings per share amounts, basic net income and diluted 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. Comparative earnings per share data for prior
periods presented has been restated to conform to the new standard.
Reclassifications
Certain reclassifications have been made to the 1996 and 1995
financial statements to conform with the 1997 presentation.
25
26
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
3. Fair value of financial instruments
Financial instruments consist of cash and short-term investments,
whose carrying amounts are not materially different from their fair
values because of the short maturity of those instruments. Cash
equivalents consist principally of commercial paper investments. Cash
equivalents of $6.2 million and $5.9 million at December 31, 1997 and
1996, respectively, are stated at cost, which approximates market.
The Company's short-term investments available for sale at
December 31, 1997 and 1996 consist of one United States treasury note.
All of the short-term investments at December 31, 1997 mature in less
than two years. The carrying value of the Company's long-term debt,
which was incurred in 1996, is assumed to approximate its fair value
since it is carried at current interest rates. For the three years
ended December 31, 1997, realized and unrealized gains and losses were
insignificant to the financial statements. United States treasury
notes with an aggregate market value of $.6 million are pledged as
collateral to the California State Lands Commission as a performance
bond on the Company's Montalvo properties.
To protect the Company's revenues from potential price declines,
the Company entered into a bracketed zero cost collar hedge contract
with a California refiner covering 3,000 barrels/day of its crude oil
production. The posted price of the Company's 13 degree API gravity
crude oil was used as the basis for the hedge. The current contract
expires on August 31, 1998.
4. Concentration of Credit Risks
The Company sells oil, gas and natural gas liquids to pipelines,
refineries and major oil companies. Credit is extended based on an
evaluation of the customer's financial condition. For the three years
ended December 31, 1997, the Company has experienced no credit losses
on the sale of oil, gas and natural gas liquids.
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, 1997, the Company has not incurred losses related to these
investments.
The following summarizes the accounts receivable balances at
December 31, 1997 and sales activity with significant customers for
each of the years ended December 31, 1997, 1996 and 1995 (in thousands):
Sales
Accounts Receivable For the Year Ended December 31,
----------------------------------- ----------------------------
Customer December 31, 1997 December 31, 1996 1997 1996 1995
-------- ----------------- ----------------- ------ ------ ------
A $ 1,812 $ 2,246 $ 23,804 $ 23,067 $ 12,641
B 1,681 1,845 19,482 14,478 12,918
C 15 1,282 7,119 10,982 9,214
D 1,587 - 12,875 - -
E - - - - 5,265
------ ------ ------ ------ ------
$ 5,095 $ 5,373 $ 63,280 $ 48,527 $ 40,038
====== ====== ====== ====== ======
26
27
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):
1997 1996
Oil and gas: ------ ------
Proved properties:
Producing properties, including intangible
drilling costs $ 128,453 $ 126,361
Lease and well equipment 92,461 88,539
Unproved properties - 169
------- -------
220,914 215,069
Less accumulated depreciation, depletion
and amortization 65,828 67,995
------- -------
155,086 147,074
------- -------
Commercial and other:
Land 151 151
Buildings and improvements 4,034 3,938
Machinery and equipment 3,653 3,707
------- -------
7,838 7,796
Less accumulated depreciation 5,483 5,360
------- -------
2,355 2,436
------- -------
$ 157,441 $ 149,510
======= =======
The following sets forth costs incurred for oil and gas property
acquisition, exploration and development activities, whether
capitalized or expensed (in thousands):
1997 1996 1995
------ ------ ------
Acquisition of properties(1) $ - $ 69,330 $ 503
Exploration - 40 1,420
Development(2) 18,172 15,689 14,034
------- ------- -------
$ 18,172 $ 85,059 $ 15,957
======= ======= =======
(1) Excludes cogeneration facility costs and includes certain closing
and consultant costs related to the acquisitions.
(2) Includes cogeneration facilities.
The Company completed two significant acquisitions (Tannehill and
Formax) in 1996 for a combined purchase price of approximately $75
million, including the purchase of an 18 megawatt cogeneration facility.
The properties, which produced approximately 3,900 barrels per day of
13 degree API gravity crude oil at the end of 1997, are in the Company's
core South Midway-Sunset producing area. These acquisitions had proved
reserves of approximately 27 million barrels upon acquisition, and were
financed by utilizing working capital and long-term borrowings.
27
28
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):
1997 1996 1995
------ ------ ------
Sales to unaffiliated parties $ 67,172 $ 55,264 $ 45,773
Production costs (22,407) (17,587) (18,264)
Exploration expenses - (71) (2,012)
Depreciation, depletion and
amortization (9,731) (6,868) (6,354)
------- ------- -------
35,034 30,738 19,143
Income tax expenses (10,870) (10,230) (6,084)
------- ------- -------
Results of operations from producing
and exploration activities $ 24,164 $ 20,508 $ 13,059
======= ======= =======
6. Debt obligations
1997 1996
Long-term debt for the years ended December 31 ------ ------
(in thousands):
Revolving bank facility $ 32,000 $ 36,000
======= =======
At December 31, 1997, Berry had a $150 million unsecured three-
year revolving credit facility with NationsBank of Texas. 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 parties have bilateral rights to one additional
redetermination each year. As of December 31, 1997, the borrowing base
was $40 million and the principal amount outstanding was $32 million.
As of January 23, 1998, the borrowing base was reduced to $35 million.
The revolving period is scheduled to terminate on November 30, 1999, at
which time any unpaid balance can be converted to a four-year term
loan, amortized quarterly. Interest on amounts borrowed is charged at
NationsBank base rate or at London Interbank Offered Rates (LIBOR) plus
60 to 100 basis points, depending on the ratio of outstanding credit to
the borrowing base. The weighted average interest rate on outstanding
borrowings at December 31, 1997 was 6.48%. The Company pays a
commitment fee of 20 to 35 basis points on the available unused portion
of the commitment. The credit agreement contains various restrictive
covenants as defined in the agreement.
In conjunction with the purchase of Tannehill in November 1996,
the Company incurred $6.9 million in short-term notes, which were due
and paid on January 6, 1997.
28
29
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
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.
In December 1989, the Company adopted a Shareholder Rights
Agreement and declared a dividend distribution of one Right for each
outstanding share of Capital Stock. Each Right, when exercisable,
entitles the holder to purchase one one-hundredth of a share of a
Series A 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 in December 1999 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 A Junior Participating
Preferred Stock and reserved for issuance upon exercise of the Rights.
In conjunction with the acquisition of Tannehill, the Company
issued a Warrant Certificate to the beneficial owners of Tannehill Oil
Company. This Warrant authorizes the purchase of 100,000 shares of
Berry Petroleum Company Class A Common Stock until November 8, 2003 at
$14.06 per share. All the warrants are currently outstanding and the
underlying shares will not be registered under the Securities Act of 1933.
The Company issued 47,621, 13,932, and -0- shares in 1997, 1996
and 1995, respectively, through its stock option plans.
At December 31, 1997, dividends declared on 4,041,400 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.
29
30
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
8. Income taxes
The Provision for income taxes consists of the following (in
thousands):
1997 1996 1995
----- ----- -----
Current:
Federal $ 3,502 $ 3,519 $ 5,089
State 995 1,027 2,042
------ ------ ------
4,497 4,546 7,131
------ ------ ------
Deferred:
Federal 3,940 4,322 828
State 544 880 (673)
------ ------ ------
4,484 5,202 155
------ ------ ------
Total $ 8,981 $ 9,748 $ 7,286
====== ====== ======
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):
1997 1996
Deferred tax asset ------ ------
Federal benefit of state taxes $ 1,900 $ 1,710
Credit/deduction carryforwards 1,440 -
Other, net 415 448
------- ------
3,755 2,158
------- -------
Deferred tax liability
Depreciation and depletion (24,069) (18,529)
State taxes, net of federal benefit (4,546) (4,002)
Other, net (619) (622)
------- -------
(29,234) (23,153)
------- -------
Net deferred tax liability $ (25,479) $ (20,995)
======= =======
30
31
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
8. Income taxes (cont'd)
Reconciliation of the statutory federal income tax rate to the
effective income tax rate follows:
1997 1996 1995
------ ------ ------
Tax computed at statutory federal rate 35.0% 35.0% 35.0%
Asset acquisition/sale differences - - 6.7
State income taxes, net of federal benefit 3.5 4.5 4.6
Tax credits (7.6) (4.5) (5.7)
Other .9 .7 (3.2)
------ ------ ------
Effective tax rate 31.8% 35.7% 37.4%
====== ====== ======
The Company has $.3 million of loss carryforwards which may be
utilized in future years to reduce the Company's federal income taxes.
These loss carryforwards expire in the year 2000. The Company also has
approximately $2.2 million of federal and $1.0 million of state
enhanced oil recovery (EOR) tax credit carryforwards available to
reduce future income taxes. The EOR credits will expire in the year
2012, if not previously utilized.
The Company went to trial in April 1993 before the U.S. Tax Court
on certain federal tax issues relating to the years 1987 through 1989.
The Court's decision was rendered in May 1995, resulting in an
approximate $.5 million charge. The Company is pursuing an appeal of
the Court's decision with respect to certain issues to the U.S. Court
of Appeals (Ninth Circuit) and a hearing was held in March 1997 with a
decision expected in the near future.
31
32
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
9. Stock option and stock appreciation rights plans
The Company has a 1987 Nonstatutory Stock Option Plan (the NSO
Plan) and a 1987 Stock Appreciation Rights Plan (the SAR Plan). The
NSO Plan provided for the granting of options (Options) to purchase up
to an aggregate of 700,000 shares of Common Stock. The SAR Plan
originally authorized a maximum of 700,000 shares of Common Stock
subject to stock appreciation rights (SARs). Holders of SARs have the
right upon exercise to receive a payment, payable at the discretion of
the Compensation Committee in cash or in shares of Common Stock, equal
to the amount by which the market price exceeds the Base Price (as
defined) with respect to the shares subject to such SARs on the date of
exercise. In December 1994, the Board of Directors adopted a
resolution to terminate the 1987 Stock Appreciation Rights Plan without
utilizing the 307,860 SARs which were still available for issuance.
The 1,120 outstanding SARs at year end were exercised in early 1998.
Total compensation expense recognized for the SAR Plan in 1997, 1996
and 1995 was $-0-, $.1 million and $-0-, respectively.
On December 2, 1994, the Board of Directors of the Company adopted
the Berry Petroleum Company 1994 Stock Option Plan (the 1994 Plan).
The 1994 Plan was approved by the shareholders in May 1995 and provides
for the granting of stock options to purchase up to an aggregate of
1,000,000 shares of Common Stock. All Options, with the
exception of the formula grants to non-employee Directors, will be
granted at the discretion of the Compensation Committee of the Board of
Directors. The term of each Option may not exceed ten years from the
date the Option is granted.
On December 5, 1997, June 2, 1997 and December 6, 1996, 200,000,
40,000 and 480,000 Options, respectively, were issued to certain key
employees at an exercise price of $19.375, $15.50 and $14.00 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 are eligible to receive 3,000 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, 30,000,
33,000 and 33,000 Options, respectively, were issued on December 2, 1997,
1996 and 1995, (3,000 Options to each of the non-employee Directors each
year) at an exercise price of $18.9375, $13.75 and $10.625 per share,
respectively.
The Company applies APB No. 25 and related interpretations in
accounting for its stock option plans. Accordingly, since the stock
options related to the 1987 Plan were issued at prices below the
existing current market prices and they were fully vested previously,
compensation related to this plan was recorded in prior years. The
Options issued per the 1994 Plan were issued at market price.
Compensation recognized related to this plan was $.5 million in 1997,
$.1 million in 1996 and $-0- in 1995.
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:
1997 1996 1995
------ ------ ------
Dividend - $/year $ .40 $ .40 $ .40
Expected option life-years 4 4 4
Volatility 26.03% 24.97% 24.97%
Risk-free interest rate 5.48% 6.10% 6.10%
32
33
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
9. Stock option and stock appreciation rights plans (cont'd)
Had compensation cost for the 1994 Plan been based upon the fair
value at the grant dates for awards under this plan consistent with the
method of SFAS No. 123, the Company's net income and earnings per share
would have been reduced to the pro-forma amounts indicated below (in
thousands, except per share data):
1997 1996 1995
------ ------ ------
Net income as reported $ 19,260 $ 17,546 $ 12,203
Pro forma $ 19,185 $ 17,387 $ 12,066
Net income per share as reported $ .88 $ .80 $ .56
Pro forma $ .87 $ .79 $ .55
The following is a summary of stock-based compensation activity
for the years 1997, 1996 and 1995.
1997 1996 1995
--------------- --------------- --------------
Options SARs Options SARs Options SARs
Balance outstanding, ------- ------ ------- ------ ------- ------
January 1 861,229 9,200 431,141 39,740 398,141 39,740
Granted 270,000 - 513,000 - 33,000 -
Exercised (196,800) (8,080) (76,912 (30,540) - -
Canceled/expired (10,000) - (6,000) - - -
Balance outstanding, ------- ------- ------- ------- ------- -------
December 31 924,429 1,120 861,229 9,200 431,141 39,740
======= ======= ======= ======= ======= =======
Balance exercisable at
December 31 256,929 1,120 231,229 9,200 206,141 39,740
======= ======= ======= ======= ======= =======
Available for
future grant 60,800 - 320,800 - 827,800 -
======= ======= ======= ======= ======= =======
Exercise price-range $ 9.80 $ 9.80 $ 9.80 $ 9.80 $ 9.80 $ 9.80
to 19.375 to 10.00 to 14.00 to 10.00 to 10.75 to 10.00
Weighted average
remaining contractual
life (years) 9 1 9 2 8 3
Weighted average fair
value per option
granted during
the year $ 4.56 $ 3.22 $ 2.23
Weighted average option exercise price information for the years 1997,
1996 and 1995 as follows:
1997 1996 1995
------ ------ ------
Outstanding at January 1 $ 12.61 $ 10.52 $ 10.51
Granted during the year $ 18.75 $ 13.98 $ 10.63
Exercised during the year $ 11.03 $ 12.82 $ -
Expired during the year $ 14.00 $ 10.69 $ -
Outstanding at December 31 $ 14.71 $ 12.61 $ 10.52
Exercisable at December 31 $ 13.09 $ 11.02 $ 10.45
33
34
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
10. Retirement Plan
The Company sponsors a defined contribution retirement or thrift
plan (401(k) Plan) to assist all employees in providing for retirement
or other future financial needs. Employee contributions (up to 6% of
their 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 results
are achieved. Due to improved financial results, the monthly matching
contributions ranged from 6% to 9% during 1997 and 1996. The Company's
contributions to the 401(k) Plan were $.3 million in 1997 and 1996 and
$.2 million in 1995.
11. Oil Spill
In December 1993, the Company experienced a crude oil spill at its
Montalvo field in Ventura County, California. The Company reached final
settlement with the federal and state governments in February 1997.
The Company's prior accruals were adequate in settling all claims.
12. Quarterly financial data (unaudited)
The following is a tabulation of unaudited quarterly operating
results for 1997 and 1996 (in thousands, except for per share data).
Basic Diluted
1997 Operating Gross Net Net Income Net Income
- ----- Revenues Profit Income Per Share Per Share
---------- -------- -------- ----------- -----------
First Quarter $ 17,025 $ 8,952 $ 4,816 $ .22 $ .22
Second Quarter 15,988 8,787 4,652 .21 .21
Third Quarter 16,775 8,697 5,136 .23 .23
Fourth Quarter 17,327 8,533 4,656 .22 .21
------- ------- ------- ------- -------
$ 67,115 $ 34,969 $ 19,260 $ .88 $ .87
======= ======= ======= ======= =======
1996
- -----
First Quarter $ 12,145 $ 6,825 $ 3,861 $ .18 $ .18
Second Quarter 13,219 7,820 4,398 .20 .20
Third Quarter 13,433 7,063 4,012 .18 .18
Fourth Quarter 16,394 8,958 5,275 .24 .24
------- ------- ------- ------- -------
$ 55,191 $ 30,666 $ 17,546 $ .80 $ .80
======= ======= ======= ======= =======
34
35
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 for the three
years ended December 31, 1997. 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, 1997,
1996 and 1995, and changes in such quantities during each of the years
then ended were as follows (in thousands):
1997 1996 1995
--------------- --------------- ---------------
Oil Gas Oil Gas Oil Gas
Mbbls Mmcf Mbbls Mmcf Mbbls Mmcf
Proved developed and ------ ------ ------ ------ ------ ------
undeveloped reserves:
Beginning of year 101,336 4,682 77,071 5,983 75,996 6,530
Revision of previous
estimates 3,647 (869) 739 (810) 5,266 803
Production (4,503) (282) (3,491) (491) (3,277) (611)
Sale of reserves
in place (26) - - - (1,698) (739)
Purchase of reserves
in place - - 27,017 - 784 -
------- ------ ------- ------ ------- ------
End of year 100,454 3,531 101,336 4,682 77,071 5,983
======= ====== ======= ====== ======= ======
Proved developed reserves:
Beginning of year 76,358 2,608 62,856 3,380 62,718 4,727
======= ====== ======= ====== ======= ======
End of year 86,858 1,457 76,358 2,608 62,856 3,380
======= ====== ======= ====== ======= ======
35
36
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):
1997 1996 1995
----------- ----------- -----------
Future cash inflows $ 1,232,749 $ 1,875,373 $ 1,039,150
Future production and
development costs (421,305) (429,879) (311,955)
Future income tax expenses (246,668) (495,412) (245,416)
--------- --------- ---------
Future net cash flows 564,776 950,082 481,779
10% annual discount for estimated
timing of cash flows (297,182) (529,523) (273,478)
--------- --------- ---------
Standardized measure of discounted
future net cash flows $ 267,594 $ 420,559 $ 208,301
========= ========= =========
Pre-tax standardized measure of
discounted future net
cash flows $ 376,459 $ 634,579 $ 308,370
========= ========= =========
Average sales prices at December 31:
Oil ($/Bbl) $ 12.19 $ 18.37 $ 13.39
Gas ($/Mcf) $ 2.33 $ 3.02 $ 1.45
Changes in standardized measure of discounted future net cash flows
from proved oil and gas reserves (in thousands):
1997 1996 1995
-------- -------- --------
Standardized measure -
beginning of year $ 420,559 $ 208,301 $ 180,953
Sales of oil and gas produced,
net of production costs (44,765) (37,677) (27,509)
Revisions to estimates of
proved reserves:
Net changes in sales prices
and production costs (259,026) 170,529 41,726
Revisions of previous
quantity estimates 14,014 4,020 23,584
Change in estimated future
development costs (1,775) (19,294) (14,234)
Extensions, discoveries and improved
recovery less related costs - - -
Purchases of reserves in place - 171,456 2,316
Sale of reserves in place (244) - (8,645)
Development costs incurred
during the period 18,597 9,305 14,034
Accretion of discount 63,458 30,837 2,639
Income taxes 109,780 (101,936) (13,126)
Other (53,004) (14,982) 6,563
------- ------- -------
Net increase (decrease) (152,965) 212,258 27,348
------- ------- -------
Standardized measure - end of year $ 267,594 $ 420,559 $ 208,301
======= ======= =======
36
37
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 caption "Voting Securities" and "Principal
Shareholders and Ownership by Management" in the Company's definitive
proxy statement to be filed pursuant to Regulation 14A no later than
120 days after the close of its fiscal year.
Compliance with Section 16(a) of the Securities Exchange Act of 1934
Section 16(a) of the Securities Exchange Act of 1934 and related
Securities and Exchange Commission rules require that directors and
executive officers report to the Securities and Exchange Commission
changes in their beneficial ownership of Berry stock, and that any late
filings be disclosed. Based solely on a review of the copies of such
forms furnished to the Company, or written representations that no Form
5 was required, the Company believes that all Section 16(a) filing
requirements were complied with, except that one report for some shares
gifted was filed late by Mr. William F. Berry.
Item 13. Certain Relationships and Related Transactions
The information called for by Item 13 is incorporated by reference
from information under the caption "Certain Relationships and Related
Transactions" in the Company's definitive proxy statement to be filed
pursuant to Regulation 14A no later than 120 days after the close of
its fiscal year.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
A. Financial Statements and Schedules
See Index to Financial Statements and Supplementary Data in Item 8.
B. Reports on Form 8-K
None.
37
38
C. Exhibits
Exhibit No. Description of Exhibit Page
- ----------- -------------------------- ------
3.1* Registrant's Restated Certificate of Incorporation (filed as
Exhibit 3.1 to the Registrant's Registration Statement on
Form S-1 filed on June 7, 1989, File No. 33-29165)
3.2* Registrant's Restated Bylaws (filed as Exhibit 3.2 to the
Registrant's Registration Statement on Form S-1 on
June 7, 1989, File No. 33-29165)
3.3* Registrant's Certificate of Designation, Preferences and
Rights of Series A Junior Participating Preferred Stock
(filed as Exhibit 3.3 to the Annual Report on Form 10-K
for the year ended December 31, 1989, File No. 0-11708)
4.1* Rights Agreement between Registrant and Bank of America
dated as of December 8, 1989 (filed as Exhibit 1 to Form 8-K
filed on December 20, 1989, File No. 0-11708)
10.1 Description of Cash Bonus Plan of Berry Petroleum Company 43
10.2 Salary Continuation Agreement dated as of December 5, 1997,
by and between Registrant and Jerry V. Hoffman 44
10.3 Form of Salary Continuation Agreement dated as of December 5,
1997, by and between Registrant and Ralph J. Goehring and
Michael R. Starzer 47
10.4* Form of Salary Continuation Agreements dated as of
March 20, 1987, as amended August 28, 1987, by and between
Registrant and selected employees of the Company (filed as
Exhibit 10.12 to the Registration Statement on Form S-1
filed on June 7, 1989, File No. 33-29165)
10.5* Instrument for Settlement of Claims and Mutual Release by
and among Registrant, Victory Oil Company, the Crail Fund
and Victory Holding Company effective October 31, 1986
(filed as Exhibit 10.13 to Amendment No. 1 to the
Registrant's Registration Statement on Form S-4 filed on
May 22, 1987, File No. 33-13240)
10.6* 1994 Stock Option Plan (filed as Exhibit 10.8 to the
Registrant's Annual Report on Form 10-K for the year
ended December 31, 1994, File No. 1-9735)
10.7* Purchase and Sale Agreement, dated as of November 8, 1996,
by and between the Registrant and Tannehill Oil Company, Inc.,
a California corporation (filed as Exhibit 10.1 in
Registrant's Form 8-K filed on December 2, 1996,
File No. 1-9735)
10.8* Purchase and Sale Agreement, dated as of November 8, 1996,
by and between the Registrant and Tannehill Electric
Company, Inc., a California corporation (filed as
Exhibit 10.2 in Registrant's Form 8-K on December 2, 1996,
File No. 1-9735)
10.9* Purchase and Sale Agreement, dated as of November 8, 1996,
by and between the Registrant and Tannehill Oil Company,
a California general partnership, and Boyce Resource
Development Company, a California corporation; Albert G.
Boyce, Jr., as Trustee of Trust "B" Under the Will of
Albert G. Boyce, Sr., Deceased; William J. Boyce;
Albert Gallatin Boyce V; Mary Katherine Boyce; John T.
Hinkle; General Western, Inc., a New Mexico corporation;
Delmar R. Archibald Family Trust, dated June 22, 1982;
Lisle Q. Tannehill; John W. Tannehill; Gail Kay Tannehill,
as Trustee of the Gail Kay Tannehill Family Trust, dated
April 9, 1996; and Thomas H. Tannehill, all acting as
partners of Tannehill Oil Company and individually,
jointly and severally (filed as Exhibit 10.3 in
Registrant's Form 8-K filed on December 2, 1996,
File No. 1-9735)
38
39
Exhibits (cont'd)
Exhibit No. Description of Exhibit Page
- ----------- --------------------------- ------
10.10* Credit Agreement, dated as of December 1, 1996,
by and between the Registrant and NationsBank of
Texas, N.A. (filed as Exhibit 10.1 in Registrant's
Form 8-K filed on December 18, 1996, File No. 1-9735)
10.11* Stock Purchase Agreement, dated December 11, 1996,
by and between the Registrant and Exxon Corporation,
a New Jersey corporation (filed as Exhibit 10.1 in
Registrant's Form 8-K filed on December 17, 1996,
File No. 1-9735)
10.12* Standard Offer #2 Power Purchase Agreement dated
May 1984 by and between Registrant's predecessor
and Pacific Gas and Electric Company (filed as
Exhibit 10.14 in Registrant's Form 10-K filed
on March 21, 1997, File No. 1-9735)
10.13* Standard Offer #1 Power Purchase Agreement dated
January 16, 1997, by and between Registrant and
Pacific Gas and Electric Company (filed as
Exhibit 10.15 in Registrant's Form 10-K filed on
March 21, 1997, File No. 1-9735)
10.14* Warrant Certificate dated November 14, 1996, by and
between Registrant and Tannehill Oil Company (filed as
Exhibit 10.16 in Registrant's Form 10-K filed on
March 21, 1997, File No. 1-9735)
23.1 Consent of Coopers & Lybrand L.L.P. 50
23.2 Consent of DeGolyer and MacNaughton 51
27. ** Financial Data Schedule 52
99.1 Undertaking for Form S-8 Registration Statements 53
99.2* Form of Indemnity Agreement of Registrant
(filed as Exhibit 28.2 in Registrant's
Registration Statement on Form S-4 filed on
April 7, 1987, File No. 33-13240)
99.3* Form of "B" Group Trust (filed as Exhibit 28.3
to Amendment No. 1 to Registrant's Registration
Statement on Form S-4 filed on May 22, 1987,
File No. 33-13240)
* Incorporated by reference
** Included in the Company's electronic filing on EDGAR
39
40
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 10, 1998.
BERRY PETROLEUM COMPANY
/s/ JERRY V. HOFFMAN /s/ RALPH J. GOEHRING /s/ DONALD A. DALE
JERRY V. HOFFMAN RALPH J. GOEHRING DONALD A. DALE
Chairman of the Board, Senior Vice President and Controller (Principal
President and Chief Chief Financial Officer Accounting Officer)
Executive Officer (Principal Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities on the dates so
indicated.
Name Office Date
/s/ Jerry V. Hoffman Chairman of the Board , President March 10, 1998
Jerry V. Hoffman & Chief Executive Officer
/s/ Benton Bejach Director March 10, 1998
Benton Bejach
/s/ William F. Berry Director March 10, 1998
William F. Berry
/s/ Gerry A. Biller Director March 10, 1998
Gerry A. Biller
/s/ Ralph B. Busch, III Director March 10, 1998
Ralph B. Busch, III
/s/ William E. Bush, Jr. Director March 10, 1998
William E. Bush, Jr.
/s/ William B. Charles Director March 10, 1998
William B. Charles
/s/ Richard F. Downs Director March 10, 1998
Richard F. Downs
/s/ John A. Hagg Director March 10, 1998
John A. Hagg
/s/ Thomas J. Jamieson Director March 10, 1998
Thomas J. Jamieson
/s/ Roger G. Martin Director March 10, 1998
Roger G. Martin
/s/ James A. Middleton Director March 10, 1998
James A. Middleton
40