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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, 1996
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 24, 1997, the registrant had 21,067,434 shares of Class
A Common Stock outstanding and the aggregate market value of the voting stock
held by nonaffiliates was approximately $180,735,000. This calculation is
based on the closing price of the shares on the New York Stock Exchange on
February 24, 1997 of $14.50. The registrant also had 898,892 shares of Class
B Stock outstanding on February 24, 1997, 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
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
Stockholder 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 17
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 36
PART III
Item 10. Directors and Executive Officers of the Registrant 36
Item 11. Executive Compensation 36
Item 12. Security Ownership of Certain Beneficial Owners
and Management 36
Item 13. Certain Relationships and Related Transactions 36
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 37
3
PART I
Items 1 and 2. Business and Properties
Introduction
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, 1996. 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. The Company's
primary growth focus is on opportunities in California. 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, 1996, the Company's estimated proved reserves were
102.1 million barrels of oil equivalent, (BOE), of which 99.2% is crude oil.
Substantially all of the Company's reserves are located in California with
94% and 5.8% of total reserves in Kern and Ventura Counties, respectively.
Approximately 75% of the reserves are owned in fee. 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 1996 was 3.6 million BOE,
up 6% from 1995 production of 3.4 million BOE. For the five years 1992
through 1996, the Company's average reserve replacement rate was 273% at a
cost of $2.54 per BOE. In 1996, the Company replaced 767% of its production
at $2.84 per BOE. For the five year period, the Company's reserve replacement
rate is higher than the industry average, and the finding cost per barrel is
lower than the industry average.
Acquisitions
The Company completed two significant acquisitions in 1996, both occurring in
the fourth quarter. In November, the Company acquired the Tannehill
producing properties (Tannehill), which included an 18 megawatt cogeneration
facility, for approximately $25.5 million. In December, the Company acquired
the Formax producing properties (Formax) for approximately $49.5 million.
The Tannehill and Formax properties produced approximately 2,350 barrels per
day of heavy crude oil as of February 24, 1997, and are located adjacent to
and in-between the Company's core South Midway-Sunset properties. The proved
reserves associated with these acquired properties are approximately 27
million barrels. The combined purchase price of approximately $75 million
was financed by existing working capital and $39 million of long-term debt.
To finance the Formax acquisition, the Company entered into a $150 million
unsecured three-year revolving credit facility with a major energy lender
establishing an initial borrowing base of $50 million on December 1, 1996.
The financing cost of the first $50 million under the agreement is at the
London Interbank Offered Rates (LIBOR) plus 60 basis points, or approximately
6.25% at current market rates.
4
Operations
The Midway-Sunset field contains predominantly heavy crude oil, the
production of which depends substantially on steam injection. Berry utilizes
primary, cyclic steaming and steam flooding 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 facilities (LACT) and transferred into crude oil pipelines owned by
other oil companies. The point-of-sale is usually at the LACT unit.
Revenues
The percentage of revenues by source for the prior three years is as
follows:
1996 1995 1994
Sales of oil and gas 97% 89% 95%
Interest and other income 3% 11% 5%
See Berry's Statements of Operations and accompanying Notes thereto.
Oil Marketing
The market for hydrocarbons continues to be quite volatile. California
crude oil pricing fundamentals improved in 1996 with declining Alaska
production and the legislative approval to export Alaska North Slope crude
oil. 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. 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 1996.
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. Refinery upsets (fires,
explosions, extended turnarounds, etc.) can impact local crude prices, for
limited times, by weakening crude demand. As a result of large investments
required by the refinery industry in California to meet product
specifications and clean air regulations, the number of individual refineries
has decreased. As a result, individual 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 the future
crude oil markets. Berry's 1996 average heavy crude oil sales price was
$15.42 per barrel, up $1.86 per barrel, or 14%, from $13.56 in 1995 (both
years are net of any hedging). The Company hedged approximately 3,000
barrels per day, or 31% of its 1996 production by entering into two bracketed
zero cost collar hedge contracts with a California independent refiner.
These contracts expired on January 31, 1997. In late February 1997, the
Company entered into a similar hedge contract for approximately 25% of its
current production for a term of 18 months.
To provide additional marketing flexibility, the Company owns a blending
facility located near its South Midway-Sunset properties. The Company
suspended the blending operations in December 1993 due to the high cost of
natural gasoline, the improved demand for the Company's 13 degree API gravity
heavy crude oil, and the narrowing margin between the posted price of the
blended crude oil and the heavy crude oil. Up to 5,000 barrels per day of the
Company's heavy crude oil can be blended with lighter crude oils and natural
gasolines to produce a blended crude oil of approximately 27 degree API
gravity. At times, this blending operation may allow the Company to improve
the profit margin on the sale of its heavy crude oil. Blending also allows
the Company the option to ship through common carrier pipelines and sell
directly to refiners in the Los Angeles basin, the San Francisco Bay area
and the Mid-Continent. While no blending has occurred since 1993, the
Company has the ability to resume blending operations if warranted by
market conditions.
5
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 reserves, or 96 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 purchasing two gas-fired cogeneration facilities.
Steam generation from these facilities is more efficient than conventional
steam generators, as both steam and electricity are produced from the same
gas supply used as fuel. 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 continues toward
deregulation, this relationship may change and electricity revenues may be
impacted by other factors in addition to natural gas prices. Proceeds
received from the sale of electricity produced by the Company's cogeneration
facilities are reported as a reduction in operating costs.
For its South Midway-Sunset properties, the Company's current steam
production is generated by the two cogeneration facilities (approximately
18,500 barrels of steam per day (BSPD)) and, as needed, from conventional
steam generators. In addition, the Company is making modifications to use
the duct-firing capability of its 38 megawatt facility which is expected to
produce up to an additional 6,000 BSPD available for delivery to the recently
acquired Formax properties. 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.
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 barrels and as emergency back-up steam generation to the
cogeneration facilities. Conventional steam generation is the sole source of
steam at the North Midway-Sunset properties. Current oil prices, near-term
oil price expectations and natural gas prices are the primary factors
determining steam levels generated from conventional generators.
The Company's two cogeneration facilities sold electricity to a large
California-based utility under Standard Offer 2 contracts (SO2) 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 December 31,
2001. The SO2 contract for the 38 megawatt facility has been replaced by a
Standard Offer 1 (SO1) contract effective January 16, 1997, which will result
in lower electricity revenues for the 38 megawatt facility. However, under
the SO1 contract, the Company will continue to receive Short Run Avoided Cost
(SRAC) pricing plus a portion of the proceeds related to available capacity
that were received in 1996. Proposed 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. 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 expires in April 1997 and the take-or-
pay requirements were substantially satisfied in January 1997. As a result,
the Company expects substantial reductions in its gas transportation costs in
1997 and beyond.
6
Environmental and Other Regulations
The operations of Berry are affected in varying degrees 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.
Berry, as an owner and operator of oil and gas properties, is subject to
various federal, state, regional and local laws and regulations relating to
discharge of materials into, and protection of, the environment. These laws
and regulations may, among other things, impose liabilities on the owner or
the lessee in the case of leased properties for the cost of pollution
clean-up resulting from operations, subject the owner or lessee to liability
for pollution damages, require suspension or cessation of operations in
affected areas, and impose restrictions on the injection of liquids into
subsurface aquifers that may contaminate groundwater.
Berry has made and will continue to make expenditures in its efforts to
comply with these requirements, which it believes are necessary business
costs in the oil and gas industry. Berry has established policies for
continuing compliance with environmental laws and regulations affecting its
production. The costs incurred by these policies and procedures 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.
Although environmental requirements do have a substantial impact upon
the energy industry, generally these requirements do not appear to affect
Berry any differently, or to any greater or lesser extent, than other
companies in California and in the domestic industry as a whole. Berry does
not believe that compliance with federal, state, regional or local laws
regulating the discharge of materials into the environment, or otherwise
relating to the protection of the environment, will have a material adverse
effect upon the capital expenditures, earnings or competitive position of the
Company, but there is no assurance that changes in or additions to laws or
regulations regarding the protection of the environment will not have such an
impact.
Berry's properties in the Montalvo field have greater environmental
risks due to their location near the Pacific Ocean. In Berry's case, a small
oil spill that endangers tidal waters could immediately involve significant
clean-up, regulatory investigation and penalties, any or all of which could
subject the Company to a significant financial burden. In addition to
purchasing insurance to cover certain environmental risks, the Company
mitigates this exposure by the development and implementation of emergency
response and major oil spill prevention and contingency plans. The Company
is also a contract associate member of Clean Seas, an organization with
significant experience and resources to contain and minimize the effects of
an oil spill.
The Company experienced an oil spill due to a ruptured pipe on its
Montalvo field in December 1993 which required cleanup of the area directly
around the pipe, an agricultural runoff pond and the nearby beach and ocean.
Although 100% of the Montalvo field's wells and facilities are onshore, part
of the spilled crude oil was pumped into the ocean from the agricultural
runoff pond by an agricultural worker. The Company initiated procedures and
made operational improvements to reduce the likelihood of a similar future
event. See Item 3. "Legal Proceedings" and Note 12 to the Company's
financial statements.
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, other than described
herein, existing as of December 31, 1996, which would have a material impact
upon the Company's financial position or results of operations.
7
Competition
The oil and gas industry is highly competitive. As an independent
producer, the Company does not own any refining or retail outlets. It has
little control over the price it receives for its crude oil, and 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, 1996, the Company had 98 full-time employees.
Acquisition and Disposition of Properties
The Company spent approximately $75 million on property acquisitions
(Tannehill and Formax), including the purchase of an 18 megawatt cogeneration
facility, and $9.4 million on development programs in 1996. The Company's
1997 budget for capital expenditures on development activities, including
facilities, is $16.4 million of which 54% is earmarked for exploitation of
Tannehill and Formax. As these activities are influenced by numerous factors
including, but not limited to, drilling results, oil and natural gas prices,
availability of equipment, regulatory restrictions, etc., many of which are
outside the Company's control, the actual expenditure level may vary
considerably from budgeted levels.
In 1995, the Company sold its Rincon properties located in Ventura
County, California, which comprised 1,631 acres and 15 producing wells and
represented approximately 3% of its net daily production and 2% of its
reserves.
Oil and Gas Properties
Development
South Midway-Sunset - Berry owns and operates working interests in
eighteen properties containing 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 84% of its
current daily production. The wells produce from an average depth of
approximately 1200 feet. These properties rely on thermally enhanced oil
recovery methods, primarily cyclic steaming. Twelve of these properties,
which are owned in fee, accounted for approximately 74% of Berry's average
daily production during 1996 and represent 75% of the Company's proved oil
and gas reserves.
During 1996, a total of 39 development wells were drilled and completed
on these properties. The objective of this work was to maintain and
accelerate productive capacity in the Company's single largest asset.
Included in the above program were two horizontal wells. This improving
technology was used on producing wells, the goal of which is to act as basal
drainage points in mature areas of the Monarch reservoir, and provide more
efficient reservoir depletion. The Company is monitoring these wells to
determine the appropriate future application to its properties, with its
objective being to accelerate production, improve ultimate recovery of
original oil-in-place and to reduce the development and operating costs of
the properties.
North Midway-Sunset - Berry owns and operates approximately 1,824 acres
in the North Midway-Sunset field which account for approximately 9% of the
Company's proved oil and gas reserves and approximately 9% of its current
daily production. These properties rely on thermally enhanced oil recovery
methods, primarily cyclic steaming and steam flooding. Berry's interests
consist of four fee properties comprising 1,009 acres and seven leases
comprising 815 acres. The wells produce from an average depth of
approximately 1200 feet.
8
During 1996, the Company drilled one Potter well, deepened one existing
Potter well and drilled seven wells in the Mya sand reservoir. The objective
of this work was to maintain productive capacity and develop proven reserves.
Two of the Mya sand wells drilled were on the Section 12 property acquired
in 1995. The Mya program established significant follow-up potential.
Montalvo - Berry owns 100% of the working interest in six leases in
Ventura County, California in the Montalvo field. Two of the six leases are
owned by the State of California. 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, containing 8,563 acres,
represents approximately 7% of Berry's total current daily oil and gas
production. The wells produce from an average depth of approximately 12,500
feet. The Company's 1996 efforts were directed at improving efficiency,
lowering operating cost and further reducing environmental risk.
Exploration
The Company did not participate in the drilling of any exploration wells
in 1996. Although the Company has significantly reduced its exploration
program since 1994 to concentrate on improving profitability and strategic
acquisitions, the Company may investigate and pursue a focused exploration
program in the future.
Oil and Gas Reserves
Reserve Reports - The Company engaged DeGolyer and MacNaughton (D&M) to
estimate the proved oil and gas reserves and the future net revenues to be
derived from such properties of the Company for the three years ended
December 31, 1996 for all of the Company's properties. D&M is an independent
oil and gas reserve engineering firm. In preparing their reports for the
three years ended December 31, 1996, they reviewed and examined such
geological, economic, engineering and other data provided by the Company as
considered necessary under the circumstances applicable to each reserve
report. They also examined the reasonableness of certain economic
assumptions regarding estimated operating and development costs and recovery
rates in light of economic circumstances as of December 31, 1996, 1995 and
1994. For the Company's operated properties, 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:
1996 1995 1994
Net Annual Production(1):
Oil (Mbbls) 3,491 3,277 3,250
Gas (Mmcf) 491 611 793
Total equivalent barrels (2) 3,573 3,379 3,382
Average Sales Price:
Oil (per bbl) $ 15.42 $ 13.56 $ 11.61
Gas (per mcf) 1.99 1.50 1.87
Per BOE 15.36 13.48 11.60
Average Production Cost (per BOE) 4.92 5.41 6.28
(1) Net production represents production owned by Berry and produced
to its interest, less royalty and other similar interests. All oil and gas
produced, other than lease fuel needs, is sold at the well site. Berry does
not refine any of its production.
(2) Equivalent oil and gas information is at a ratio of 6,000 cubic
feet of natural gas to one barrel (bbl) of oil.
9
Acreage and Wells
At December 31, 1996, the Company's properties accounted for the
following developed and undeveloped acres:
Developed Acres Undeveloped Acres
Gross Net Gross Net
California 6,943 6,820 6,846 6,846
Other 1,250 220 - -
----- ----- ----- -----
8,193 7,040 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 2,108 gross oil wells (2,095 net) and 8 gross gas
wells (4 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:
1996 1995 1994
Gross Net Gross Net Gross Net
Exploratory Wells
Drilled:
Productive 0 0.0 0 0.0 0 0.0
Dry (1) 0 0.0 4 0.7 4 0.8
Development Wells
Drilled:
Productive 46 45.1 44 44.0 14 14.0
Dry (1) 3 2.1 1 1.0 0 0.0
Total Wells Drilled:
Productive 46 45.1 44 44.0 14 14.0
Dry (1) 3 2.1 5 1.7 4 0.8
(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.
As of February 24, 1997, no exploratory wells were being drilled nor are
budgeted to be drilled in 1997.
10
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.
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.
Item 3. Legal Proceedings
On December 25, 1993, a crude oil spill was discovered on the Company's
Montalvo field in Ventura County, California. The Company estimates that the
total discharge was approximately 2,100 barrels. The Company paid $.6
million to settle all potential state criminal claims against the Company in
August 1994. The Company reached a final settlement for civil damages and
penalties with the federal and state governments in January 1997 and a
consent decree was approved and entered by the U.S. District Court in Los
Angeles, California on February 14, 1997. The Company, without admitting any
liability, agreed to pay approximately $3.2 million to federal and state
agencies for response and assessment costs, civil damages and penalties
arising from this incident. The Company received reimbursement under its
insurance policy for approximately $2.3 million of the settlement amount. As
of December 31, 1996 and February 24, 1997, the Company had received
approximately $9.8 million and $11.2 million, respectively, under its
insurance coverage as reimbursement for costs incurred and paid by the
Company associated with the spill. Management believes that its previous
accruals are adequate.
Information relating to the tax matters appeal to the U.S. Court of
Appeals (Ninth Circuit) is set forth in Note 9 to the Company's financial
statements.
Item 4. Submission of Matters to a Vote of Security Holders
None.
11
EXECUTIVE OFFICERS
Listed below are the names, ages (as of December 31, 1996) and positions
of the executive officers of Berry and their business experience during at
least the past five years.
JERRY V. HOFFMAN, 47, 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 prior subsidiaries or successors since February 1985.
DONALD A. DALE, 50, Controller since December 1985. Mr. Dale, a CPA,
was the Controller for Berry Holding Company from September 1985 to December
1985.
RALPH J. GOEHRING, 40, Chief Financial Officer since March 1992 and
Manager of Taxation from September 1987 until March 1992. Mr. Goehring, a
CPA, is also the Assistant Secretary for Berry Petroleum Company.
CHESTER L. LOVE, 62, Vice President of Engineering since March 1994 and
Manager of Engineering from May 1992 to March 1994. Mr. Love, a registered
petroleum engineer, was previously Vice President of Consulting for
Scientific Software-Intercomp from 1979 to 1992.
KENNETH A. OLSON, 41, 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 prior subsidiaries or successors since
July 1985.
MICHAEL R. STARZER, 35, 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, 46, Manager of Production since March 1993, 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.
12
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
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 Stockholder 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, 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 1996 and 1995 are shown below:
1996 1995
Price Range Dividends Price Range Dividends
High Low per Share High Low per Share
First Quarter $ 11 1/8 $ 8 3/4 $ .10 $ 10 $ 8 3/4 $ .10
Second Quarter 12 1/2 10 3/8 .10 10 7/8 9 .10
Third Quarter 11 3/4 10 3/8 .10 10 5/8 9 3/8 .10
Fourth Quarter 14 1/2 11 1/4 .10 10 7/8 9 7/8 .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
24, 1997, December 31, 1996 and December 31, 1995 was $14.50, $14.375 and
$10.125, respectively.
The number of holders of record of the Company's Common Stock and Class
B Stock as of February 24, 1997 was approximately 1,010 and 1, respectively.
The Company has paid cash dividends for many years prior to the roll-up
of the various Berry companies into Berry Petroleum Company on December 16,
1985. However, since Berry's formation, the Company has paid dividends on
its Common Stock for 8 consecutive semi-annual periods through September 1989
and for 29 consecutive quarters through December 31, 1996. 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.
Dividends declared on 4,366,400 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.
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, 1996 were derived from the audited
financial statements and the accompanying notes to those financial statements
(in thousands, except per share and per barrel data):
1996 1995 1994 1993 1992
Statement of Operations Data:
Sales of oil and gas $ 55,264 $ 45,773 $ 39,451 $ 42,843 $ 49,598
Operating costs (excluding DD&A
and exploratory dry hole costs) 17,587 18,264 21,224 23,790 20,931
General and administrative
expenses (G&A)(excluding DD&A) 4,820 4,578 5,118 5,999 5,511
Depreciation, depletion &
amortization (DD&A) 7,323 6,847 7,270 9,983 8,123
Net income (loss) 17,546 12,203 (1,129) 32 10,115
Net income (loss) per share .80 .56 (.05) - .46
Weighted average number
of shares outstanding 21,939 21,932 21,932 21,926 21,915
Balance Sheet Data:
Working capital $ 7,850 $ 36,506 $ 38,273 $ 40,418 $ 50,642
Total assets 176,403 117,722 118,254 135,159 140,140
Long-term debt 36,000 - - - -
Shareholders' equity 101,009 92,060 88,632 98,323 109,690
Cash dividends per share .40 .40 .40 .55 .60
Operating Data:
Cash flow from operations 29,182 17,070 14,579 10,957 22,169
Capital expenditures(excluding
acquisitions) 15,616 14,569 5,911 13,983 9,869
Property Acquisitions (1) 69,330 503 1,023 - 2,311
Per BOE:
Sales price $ 15.36 $ 13.48 $ 11.60 $ 11.43 $ 12.75
Operating costs 4.92 5.41 6.28 6.35 5.43
G&A 1.35 1.35 1.51 1.60 1.43
------ ------ ------ ------ ------
Cash flow 9.09 6.72 3.81 3.48 5.89
DD&A 2.05 2.03 2.15 2.67 2.11
------ ------ ------ ------ ------
Operating income $ 7.04 $ 4.69 $ 1.66 $ .81 $ 3.78
====== ====== ====== ====== ======
Production:
Oil (Bbls) 3,491 3,277 3,250 3,617 3,683
Gas (Mcf) 491 611 793 771 1,029
Total (BOE) 3,573 3,379 3,382 3,746 3,855
Proved Reserves Information:
Oil (Bbls) 101,336 77,071 75,996 72,078 72,434
Gas (Mcf) 4,682 5,983 6,530 5,476 10,003
Total (BOE) 102,116 78,068 77,084 72,991 74,101
Present value(NPV10)of
estimated future
cash flow before
income taxes $634,579 $308,370 $263,890 $ 50,124 $155,546
(1) Excludes cogeneration facility costs and includes certain closing and
consultant costs related to the acquisitions.
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, 1996 and the
financial condition, liquidity and capital resources as of December 31, 1996.
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 market conditions, regional and other factors. The
aggregate amount of oil and gas produced may fluctuate based on development
and exploitation of oil and gas reserves pursuant to current reservoir
management plans. Production rates, steam costs, labor and maintenance
expenses 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 1996 was $17.5 million, up $5.3 million and $18.6
million, respectively, from net income of $12.2 million in 1995 and a loss of
$1.1 million in 1994. For the fourth quarter of 1996, net income was $5.3
million, up $1.6 million, or 43%, from $3.7 million in the fourth quarter of
1995 and $1.3 million, or 32.5%, from $4.0 million in the third quarter of
1996. The improvement in profitability in 1996 versus 1995 was primarily due
to higher oil prices and production, lower operating costs and the reduction
in dry hole costs, offset partially by the gain on the sale of the Rincon
properties in 1995.
1996 1995 1994
Production - BOE Per Day 9,762 9,258 9,266
Averages Sales Price - Per BOE $15.36 $13.48 $11.60
Operating Cost - Per BOE 4.92 5.41 6.28
DD&A - Per BOE 2.05 2.03 2.15
G&A - Per BOE 1.35 1.35 1.51
Operating income from producing operations was $30.7 million, up $9.6
million from 1995 and $19.8 million from 1994, or 45% and 166%, respectively,
from $21.2 million in 1995 and $11.6 million in 1994. The improvement was
primarily due to higher oil prices, lower operating costs and higher
production.
The average sales price received per BOE during 1996 of $15.36 was 14%
and 32% higher than $13.48 and $11.60 received in 1995 and 1994,
respectively. Oil and gas production of 9,762 BOE per day was 504 and 496
BOE per day higher than 1995 and 1994, respectively, primarily due to the
Company's 1996 development program and property acquisitions in the fourth
quarter of 1996. Production for 1994 and 1995 includes the Rincon properties
sold on November 1, 1995, which produced approximately 280 BOE per day.
The Company maintained two bracketed zero cost collar hedge contracts
with a California refiner to protect the Company's revenue from potential
price declines. The contracts were initiated in 1995 and early 1996 and
covered approximately 31% of the Company's crude oil sales. These contracts
expired in January 1997. Because of the rise in crude oil prices which
occurred during 1996, the hedge contract lowered the average sales price
received for the Company's crude oil by approximately $.37 per BOE. In late
February 1997, the Company entered into a similar hedge contract for
approximately 25% of its current production for a term of 18 months.
15
Operating costs in 1996 declined 9% and 22% from 1995 and 1994,
respectively, to $4.92 per BOE largely due to the benefit of owning and
operating for a full year the Company's 38 megawatt cogeneration plant, which
was purchased in August 1995. In addition, the Rincon properties, which
incurred high operating costs, were sold in November 1995 and various cost
reduction measures were initiated on the Company's properties. The Company
includes production taxes in its operating costs. On a BOE basis, the amount
of production taxes were $.48, $.45 and $.47 for 1996, 1995 and 1994,
respectively.
DD&A per BOE in 1996 increased slightly to $2.05 from $2.03 in 1995 and
$2.02 in 1994. The increase was primarily related to property acquisitions
in the fourth quarter of 1996. The Company expects higher DD&A costs in the
future, in both real terms and on a BOE basis, due to acquisitions.
On November 19, 1996, the Company acquired Tannehill, which included an
18 megawatt cogeneration facility, for approximately $25.5 million. On
December 13, 1996, the Company acquired Formax for approximately $49.5
million. These producing properties are adjacent to and in-between the
Company's core South Midway-Sunset producing properties and, as of February
24, 1997, produce approximately 2,350 barrels per day of 13 degree API gravity
crude oil. The Company expects production from these newly acquired
properties to exceed 3,500 barrels per day by the end of 1997. The 18
megawatt cogeneration facility located on Tannehill will be integrated into
the Company's South Midway-Sunset operations to optimize steam usage and
reduce costs.
General
Interest income in 1996 was $2.1 million, up from $2 million in 1995 and
$1.6 million in 1994, due primarily to higher cash reserves resulting from
the Company's strong cash flow in 1996. The Company anticipates that its
interest income for 1997 will decrease significantly, and the Company will
incur net interest expense due to the incurrence of long-term financing used
to acquire Formax.
G&A was $4.8 million in 1996, up 4% from $4.6 million in 1995, but down
6% from $5.1 million in 1994. The Company remains focused on cost control in
all areas and, on a per barrel basis, G&A was $1.35 per BOE in 1996,
unchanged from 1995, but down 11% from 1994. The Company anticipates that
its total G&A costs will increase modestly in 1997, but that the G&A per BOE
will decline due to the higher production levels expected in 1997.
The Company's effective income tax rate in 1996 was 36%, down slightly
from the 1995 effective rate of 37%. This lower rate for 1996 was the result
of increased development activity by the Company which generated additional
tax credits for federal and California tax purposes. The tax benefit of
42.1% for 1994 was the result of pre-tax losses for that year impacted by
certain tax benefits.
In the fourth quarter of 1996, the Company adopted the disclosure option
of Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting
for Stock-Based Compensation." As permitted in this pronouncement, the
Company opted to continue to apply the accounting provisions of Accounting
Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to
Employees," to its stock-based employee compensation arrangements. The
disclosure requirements of SFAS No. 123 are presented in Note 10 to the
Company's financial statements.
In the fourth quarter of 1995, the Company adopted SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of." This adoption resulted in no charges to the Company's
financial statements in 1996 or 1995 and is not significantly different than
the Company's impairment policy in effect prior to the adoption.
16
Financial Condition, Liquidity and Capital Resources
Working capital as of December 31, 1996 was $7.8 million, down from
$36.5 million and $38.3 million at December 31, 1995 and December 31, 1994,
respectively. Cash flow provided by operating activities of $29.2 million
was up 71% and 100% from $17.1 million and $14.6 million in 1995 and 1994,
respectively. Cash flow was higher in 1996 due to higher oil prices, lower
operating costs and higher production. Working capital declined $28.7
million from December 31, 1995, due to the use of cash and the assumption of
$6.9 million in short-term debt for the two acquisitions completed in the
fourth quarter of 1996. Other significant uses of working capital included
the payment of $8.8 million in dividends and $9.9 million in capital
expenditures primarily to develop the Company's existing producing properties
including the drilling of 49 development wells. The Company's 1997 capital
expenditure program, which includes the drilling of approximately 90 new
wells, is estimated to be $16.4 million and will be financed through
internally generated cash flow.
On December 1, 1996, the Company established a $150 million unsecured
three-year revolving credit facility with NationsBank of Texas. In
conjunction with the purchase of Tannehill and Formax, the Company borrowed
$36 million in long-term debt and incurred $6.9 million in short-term notes
which were due and paid on January 6, 1997. The Company is carrying $39
million in long-term debt under this credit facility as of February 24, 1997.
The total proved reserves at December 31, 1996 were 102.1 million BOE,
up 31% from 78.1 million BOE at December 31, 1995 and up 32% from 77.1
million BOE at December 31, 1994. After production of 3.6 million BOE, the
Company's proved reserves increased 27.6 million BOE, or 767% of 1996
production. The increase 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 $635 million at December 31, 1996, a 106% and 141% increase from
$308 million and $264 million at December 31, 1995 and 1994, respectively.
Future Developments
Proposed deregulation of the electricity generation market in California
may have a positive or negative impact on the Company's future electricity
revenues, and may impact the beneficial hedge on gas prices the Company
currently enjoys. In addition, the underlying value of the cogeneration
facilities may be impacted as the outcome of deregulation becomes more
apparent.
In 1996, the American Institute of Certified Public Accountants issued
Statement of Position (SOP) 96-1, "Environmental Remediation Liabilities,"
effective for fiscal years beginning after December 15, 1996. Management
does not believe that adoption of the provisions of this SOP will have a
material impact on the financial statements of the Company.
In 1997, the Company will adopt SFAS No. 125, "Accounting for Transfers
and Servicing of Financial Assets and Extinguishments of Liabilities."
Management does not believe that adoption of this accounting 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
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 . . . . . 18
Balance Sheets at December 31, 1996 and 1995 . . . . . . . . . . . . 19
Statements of Operations for the
Years Ended December 31, 1996, 1995 and 1994 . . . . . . . . . . . 20
Statements of Shareholders' Equity for the
Years Ended December 31, 1996, 1995 and 1994 . . . . . . . . . . . 21
Statements of Cash Flows for the
Years Ended December 31, 1996, 1995 and 1994 . . . . . . . . . . . 22
Notes to the Financial Statements . . . . . . . . . . . . . . . . . . 23
Supplemental Information About Oil & Gas Producing Activities . . . . 34
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
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, 1996 and 1995, and the related statements of operations,
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 1996. 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, 1996 and 1995, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1996, in
conformity with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P.
/s/ Coopers & Lybrand L.L.P.
February 28, 1997
Los Angeles, California
19
BERRY PETROLEUM COMPANY
Balance Sheets
December 31, 1996 and 1995
(In Thousands, Except Share Information)
1996 1995
ASSETS
Current assets:
Cash and cash equivalents $ 9,970 $ 18,759
Cash - restricted 2,570 -
Short-term investments available for sale 704 15,695
Accounts receivable 11,701 8,414
Prepaid expenses and other 1,307 2,332
------- -------
Total current assets 26,252 45,200
Oil and gas properties (successful efforts basis),
buildings and equipment, net 149,510 72,042
Other assets 641 480
------- -------
$ 176,403 $ 117,722
LIABILITIES AND SHAREHOLDERS' EQUITY ======= =======
Current liabilities:
Accounts payable $ 5,154 $ 3,086
Notes payable 6,900 -
Accrued liabilities 5,300 3,912
Federal and state income taxes payable 1,048 1,696
------- -------
Total current liabilities 18,402 8,694
Long-term debt 36,000 -
Deferred income taxes 20,992 16,968
Contingencies (Note 12)
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; 21,046,885 shares issued and
outstanding (21,033,055 in 1995) 210 210
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 53,029 52,850
Retained earnings 47,761 38,991
------- -------
Total shareholders' equity 101,009 92,060
------- -------
$ 176,403 $ 117,722
======= =======
The accompanying notes are an integral part of these financial statements.
20
BERRY PETROLEUM COMPANY
Statements of Operations
Years ended December 31, 1996, 1995 and 1994
(In Thousands, Except Per Share Data)
1996 1995 1994
Revenues:
Sales of oil and gas $ 55,264 $ 45,773 $ 39,451
Interest income (net of
interest expense) 1,903 2,040 1,616
Gain on sale of assets - 3,073 113
Other income (expense), net (72) 304 155
------- ------- -------
57,095 51,190 41,335
------- ------- -------
Expenses:
Operating costs 17,587 18,264 21,224
Depreciation, depletion &
amortization 7,323 6,847 7,270
Impairment of properties - - 2,915
Oil spill costs - - 1,344
Exploratory dry hole costs 71 2,012 5,414
General and administrative 4,820 4,578 5,118
------- ------- -------
29,801 31,701 43,285
------- ------- -------
Income (loss) before income taxes 27,294 19,489 (1,950)
Provision (benefit) for income taxes 9,748 7,286 (821)
------- ------- -------
Net income (loss) $ 17,546 $ 12,203 $ (1,129)
======= ======= =======
Net income (loss) per share $ .80 $ .56 $ (.05)
======= ======= =======
Weighted average number of shares
of capital stock used to
calculate earnings per share 21,939 21,932 21,932
======= ======= =======
The accompanying notes are an integral part of these financial statements.
21
BERRY PETROLEUM COMPANY
Statements of Shareholders' Equity
Years Ended December 31, 1996, 1995 and 1994
(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, 1994 $ 210 $ 9 $ 52,641 $ 45,463 $ 98,323
Stock options expired - - 211 - 211
Cash dividends
declared-$.40 per
share - - - (8,773) (8,773)
Net income - - - (1,129) (1,129)
----- ----- ------- ------- -------
Balances at December
31, 1994 210 9 52,852 35,561 88,632
Stock retired - - (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
===== ===== ======= ======= =======
The accompanying notes are an integral part of these financial statements.
22
BERRY PETROLEUM COMPANY
Statements of Cash Flows
Years Ended December 31, 1996, 1995 and 1994
(In Thousands)
1996 1995 1994
Cash flows from operating activities:
Net income (loss) $ 17,546 $ 12,203 $ (1,129)
Depreciation, depletion
and amortization 7,323 6,847 7,270
Gain on sale of assets - (3,073) (113)
Exploratory dryhole costs 71 1,990 5,090
Impairment of properties - - 2,915
Increase (decrease) in deferred
income tax liability 4,024 (1,985) (762)
Other, net (329) (50) 504
------- ------- -------
Net working capital provided
by operating activities 28,635 15,932 13,775
Decrease (increase) in current
assets other than cash,
cash equivalents and short-term
investments (2,262) 3,113 7,256
Increase (decrease) in current
liabilities 2,809 (1,975) (6,452)
------- ------- -------
Net cash provided by operating
activities 29,182 17,070 14,579
Cash flows from investing activities:
Capital expenditures, excluding
property acquisitions (15,616) (14,569) (5,911)
Property acquisitions (69,330) (503) (1,023)
Proceeds from sale of assets 352 6,242 327
Purchase of short-term investments (710) (3,078) (30,524)
Maturities of short-term investments 15,700 15,000 29,874
Restricted cash deposit (2,570) - -
Other, net (100) (96) (540)
------- ------- -------
Net cash provided by (used in)
investing activities (72,274) 2,996 (7,797)
Cash flows from financing activities:
Borrowings under line of credit 36,000 - -
Notes payable - Tannehill
acquisition 6,900 - -
Dividends paid (8,776) (8,773) (8,773)
Proceeds from exercise of
stock options 179 - -
------- ------- -------
Net cash provided by (used in)
financing activities 34,303 (8,773) (8,773)
Net increase (decrease) in cash
and cash equivalents (8,789) 11,293 (1,991)
Cash and cash equivalents at
beginning of year 18,759 7,466 9,457
------- ------- -------
Cash and cash equivalents
at end of year $ 9,970 $ 18,759 $ 7,466
======= ======= =======
Supplemental disclosures of cash flow
information:
Interest paid $ - $ 12 $ 5
====== ====== ======
Income taxes paid $ 4,709 $ 5,554 $ 484
====== ====== ======
The accompanying notes are an integral part of these financial statements.
23
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 98% 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
Cash equivalents consist principally of commercial paper investments.
The Company considers all highly liquid investments purchased with a
remaining maturity of three months or less to be cash equivalents. Cash
equivalents of $5.9 million and $13.4 million at December 31, 1996 and 1995,
respectively, are stated at cost, which approximates market.
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. For the three years ended December 31,
1996, 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.
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 mineral interests in oil and gas properties, to drill and complete
development wells and drill and complete exploratory wells that find proved
reserves are capitalized. Exploratory dryhole 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. 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
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
2. Summary of significant accounting policies (cont'd)
In the fourth quarter of 1995, the Company adopted Statement of
Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." This
change had no effect on the Company's financial statements. Pursuant to this
standard, assets are grouped at the lowest level for which there are
identifiable cash flows. 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.
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 the
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 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 10 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
Earnings per share is computed by dividing net income by the weighted
average number of capital shares and dilutive common stock equivalents, if
any, outstanding during the year.
Reclassifications
Certain reclassifications have been made to the 1995 and 1994 financial
statements to conform with the 1996 presentation.
25
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. The Company's short-term
investments available for sale at December 31, 1996 consist primarily of one
United States treasury note. All of the short-term investments at December
31, 1996 mature in one year or less. The carrying value of the Company's
long-term debt is assumed to approximate its fair value since it was incurred
in December 1996 at current interest rates.
To protect the Company's revenues from potential price declines, the
Company entered into two bracketed zero cost collar hedge contracts with a
California refiner covering approximately 31% 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. Both of these contracts expired in January 1997.
In late February 1997, the Company entered into a similar hedge contract for
approximately 25% of its current production for a term of 18 months.
4. Concentration of Credit Risks
The Company sells oil, gas and natural gas liquids to pipelines and
refineries. Credit is extended based on an evaluation of the customer's
financial condition. For the three years ended December 31, 1996, 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 credit
quality financial institutions and limits the amount of credit exposure to
any one financial institution. For the three years ended December 31, 1996,
the Company has not incurred losses related to these investments.
The following summarizes the accounts receivable balances at December
31, 1996 and sales activity with significant customers for each of the years
ended December 31, 1996, 1995 and 1994 (in thousands):
Sales
Accounts Receivable For the Year Ended December 31,
Customer Dec. 31, 1996 Dec. 31,1995 1996 1995 1994
A $ 2,246 $ 1,372 $ 23,067 $ 12,641 $ 16,027
B 1,845 961 14,478 12,918 11,319
C 1,282 724 10,982 9,214 -
D - - - 5,265 -
------ ------ ------ ------ ------
$ 5,373 $ 3,057 $ 48,527 $ 40,038 $ 27,346
====== ====== ====== ====== ======
26
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):
1996 1995
Oil and gas:
Proved properties:
Producing properties, including
intangible drilling costs $ 126,361 $ 55,202
Lease and well equipment 88,539 75,470
Unproved properties 169 162
------- -------
215,069 130,834
Less accumulated depreciation,
depletion and amortization 67,995 61,456
------- -------
147,074 69,378
------- -------
Commercial and other:
Land 151 151
Buildings and improvements 3,938 3,734
Machinery and equipment 3,707 4,026
------- -------
7,796 7,911
Less accumulated depreciation 5,360 5,247
------- -------
2,436 2,664
------- -------
$ 149,510 $ 72,042
======= =======
The following sets forth costs incurred for oil and gas property acquisition,
exploration and development activities, whether capitalized or expensed (in
thousands):
1996 1995 1994
Acquisition of properties(1) $ 69,330 $ 503 $ 1,023
Exploration 40 1,420 1,701
Development 15,689 14,034 4,678
------- ------- -------
$ 85,059 $ 15,957 $ 7,402
======= ======= =======
(1) Excludes cogeneration facility costs and includes
certain closing and consultant costs related to the acquisitions.
The Company completed two acquisitions in 1996 for a combined purchase
price of approximately $75 million on property acquisitions (Tannehill and
Formax), including the purchase of an 18 megawatt cogeneration facility. The
properties, which produce approximately 2,350 barrels per day of 13 degree API
gravity crude oil, on February 24, 1997, are adjacent to and in-between the
Company's South Midway-Sunset producing properties. These acquisitions have
proved reserves of approximately 27 million barrels, and were financed by
utilizing working capital and long-term borrowings.
27
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 blending operations, corporate overhead and interest
costs) for the three years ended December 31 are as follows (in thousands):
1996 1995 1994
Sales to unaffiliated parties $ 55,264 $ 45,773 $ 39,451
Production costs (17,587) (18,264) (21,224)
Exploration expenses (71) (2,012) (5,414)
Depletion, depreciation and
amortization (6,868) (6,354) (6,627)
------- ------- -------
30,738 19,143 6,186
Income tax expenses (10,230) (6,084) (1,723)
------- ------- -------
Results of operations from
producing and exploration
activities $ 20,508 $ 13,059 $ 4,463
======= ======= =======
In 1994, the Company recorded an impairment writedown of $2.9 million
related to certain oil and gas properties.
6. Debt obligations
Long-term debt for the years ended December 31 1996 1995
(in thousands):
Revolving bank facility $ 36,000 $ -
At December 31, 1996, 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 lender's customary procedures and practices. Both parties
have bilateral rights to one additional redetermination each year. As of
December 31, 1996, the borrowing base was $50 million and the principal
amount outstanding was $36 million. The revolving period is scheduled to
terminate on December 1, 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 LIBOR plus .60 to 1.00
percent, depending on the ratio of outstanding credit to the borrowing base.
The weighted average interest rate on outstanding borrowings at December 31,
1996 was 6.22% The Company pays a commitment fee of .20 to .35 percent on
the available portion of the commitment. The credit agreement contains
various restrictive covenants as defined in the agreement.
In conjunction with the purchase of Tannehill, the Company incurred $6.9
million in short-term notes, which were due and paid on January 6, 1997.
28
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 Stockholder 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 1 cent 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 13,932, 0, and 0 shares in 1996, 1995 and 1994,
respectively, through its stock option plans.
Dividends declared on 4,366,400 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.
8. Transactions with affiliates
The University Cogeneration Partners, Ltd. 1985-1, a limited
partnership, was formed in 1985 to finance the construction of a cogeneration
plant on the Company's properties. The Company also committed to purchase
the steam generated by the plant and supply the natural gas to fuel the
plant. The Company owned approximately 45% of the partnership and its
investment of $1.9 million was accounted for at cost. On August 1, 1995, the
Company purchased the remaining 55% interest in the cogeneration plant for
approximately $5.2 million. The total cost of the cogeneration plant is
included in lease and well equipment at December 31, 1996 and 1995. Amounts
paid by the Company for the steam in 1995 (through July) and 1994 were $2.6
million and $4.6 million, respectively.
29
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
9. Income taxes
The provision (benefit) for income taxes consists of the following (in
thousands):
1996 1995 1994
Current:
Federal $ 3,519 $ 5,089 $ 158
State 1,027 2,042 (56)
------ ------ ------
4,546 7,131 102
------ ------ ------
Deferred:
Federal 4,322 828 (1,077)
State 880 (673) 154
------ ------ ------
5,202 155 (923)
------ ------ ------
$ 9,748 $ 7,286 $ (821)
====== ====== ======
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 are as follows (in thousands):
Dec. 31, Dec. 31,
1996 1995
Deferred tax asset
Federal benefit of state taxes $ 1,710 $ 1,756
Net operating loss carryforwards 137 171
Credit/deduction carryforwards - 634
Other net 311 368
------ ------
2,158 2,929
------ ------
Deferred tax liability
Depreciation and depletion (18,529) (15,195)
State taxes, net (4,002) (3,122)
Other, net (622) (405)
------ ------
(23,153) (18,722)
------ ------
Net deferred tax liability $(20,995) $(15,793)
====== ======
30
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
9. Income taxes (cont'd)
Income taxes computed by applying U.S. statutory federal rates to income
(loss) before income taxes are reconciled to the provision (benefit) for
income taxes as follows (in thousands):
1996 1995 1994
Tax (benefit) computed at statutory
federal rate $ 9,553 $ 6,821 $ (663)
Increase (decrease) in taxes
resulting from:
Asset acquisition/sale
differences - 1,315 394
Percentage depletion (467) (402) (290)
State taxes, net 1,240 888 98
Enhanced oil recovery,
nonconventional fuel tax
and alternative minimum tax
credits (1,230) (1,115) (406)
Other, net 652 (221) 46
------ ------ ------
$ 9,748 $ 7,286 $ (821)
====== ====== ======
Effective tax rate 35.7% 37.4% (42.1)%
The Company has $.4 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 million of enhanced oil recovery tax credit carryforwards available to
reduce future state income taxes.
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 in the second quarter of 1995. 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 is scheduled in March 1997
with a decision expected before year end 1997.
31
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
10. 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
9,200 outstanding SARs at year end are still available for exercise under the
original terms of issuance. Total compensation expense recognized for the
SAR Plan in 1996, 1995 and 1994 was $104,000, $9,000 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 6, 1996 and December 2, 1994, 480,000 and 300,000 Options,
respectively, were issued to certain key employees at an exercise price of
$14.00 and $10.75 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 this 1994
Plan, 33,000 Options were issued on December 2, 1996, 1995 and 1994, (3,000
Options to each of the eleven nonemployee directors each year) at an exercise
price of $13.75, $10.625 and $10.75 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 $64,000 in
1996 and $0 in 1995 and 1994.
Under SFAS No. 123, compensation cost would be recognized for the fair
value of the employee's option rights. In determining the fair value, the
Company used the Black-Scholes model, assumed a dividend of $.40 per year, an
expected life of four years for all grants, an expected volatility of 24.97%
and a risk free interest rate of 6.10% for all years. 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):
1996 1995 1994
Net income (loss) as reported $ 17,546 $ 12,203 $ (1,129)
Pro forma $ 17,387 $ 12,066 $ (1,173)
Net income (loss) per share as
reported $ .80 $ .56 $ (.05)
Pro forma $ .79 $ .55 $ (.05)
32
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
10. Stock option and stock appreciation rights plans (cont'd)
The following is a summary of stock-based compensation activity for the
years 1996, 1995 and 1994.
1996 1995 1994
Options SARs Options SARs Options SARs
Balance outstanding,
January 1 431,141 39,740 398,141 39,740 142,941 69,020
Granted 513,000 - 33,000 - 333,000 -
Exercised (76,912) (30,540) - - - (5,380)
Canceled/expired (6,000) - - - (77,800) (23,900)
------- ------ ------- ------ ------- -------
Balance outstanding,
December 31 861,229 9,200 431,141 39,740 398,141 39,740
======= ====== ======= ====== ======= =======
Balance exercisable at
December 31 231,229 9,200 206,141 39,740 65,141 39,740
======= ====== ======= ====== ======= =======
Available for future
grant 320,800 - 827,800 - 860,800 39,740
======= ====== ======= ====== ======= =======
Exercise price-
range $ 9.80 $ 9.80 $ 9.80 $ 9.80 $ 9.80 $ 9.80
to 14.00to 10.00 to 10.75 to 10.00 to 10.75 to 10.00
======= ====== ======= ====== ======= =======
Weighted average
remaining contractual
life (years) 9 2 8 3 9 4
====== ====== ======= ====== ======= =======
Weighted average fair
value per option
granted during
the year $ 3.22 $ 2.23 $ 2.26
====== ====== ======
Weighted average option exercise price information for the years 1996,
1995 and 1994 as follows:
1996 1995 1994
Outstanding at January 1 $ 10.52 $ 10.51 $ 9.86
Granted during the year $ 13.98 $ 10.63 $ 10.75
Exercised during the year $ 12.82 $ - $ -
Expired during the year $ 10.69 $ - $ 9.85
Outstanding at December 31 $ 12.61 $ 10.52 $ 10.51
Exercisable at December 31 $ 11.02 $ 10.45 $ 9.88
11. Retirement Plan
The Company sponsors a defined contribution retirement or thrift plan
(401(k) Plan) to assist all employees in providing for retirement or other
future financial needs. Employee contributions (up to 6% of 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 1996 and 1995.
For 1994, all matching contributions were at the 6% rate. The Company's
contributions to the 401(k) Plan were $.3 million in 1996, $.2 million in
1995 and $.2 million in 1994.
33
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
12. Oil Spill
On December 25, 1993, the Company experienced a crude oil spill of
approximately 2,100 barrels on its PRC 735 State lease located in the
Montalvo field in Ventura County, California. The spill required clean-up of
the area directly around the pipe as well as the nearby beach and an
agricultural runoff pond. Working closely with various regulatory agencies,
the Company substantially completed the clean-up of the spill in January
1994. The Company negotiated a resolution of the state criminal
investigation for a total of $.6 million in August 1994. The Company reached
a final settlement for civil damages and penalties with the federal and state
governments in January 1997 and a consent decree was approved and entered by
the U.S. District Court in Los Angeles, California on February 14, 1997. The
Company, without admitting any liability, agreed to pay approximately $3.2
million to federal and state agencies for response and assessment costs,
civil damages and penalties arising from this incident. The Company received
reimbursement under its insurance policy for approximately $2.3 million of
the settlement amount. On December 31, 1996, the Company held cash of $2.6
million in an escrow account which was restricted for usage specifically for
this pending settlement.
The costs incurred and estimated to be incurred in connection with the
spill not yet paid by the Company are included in accrued liabilities at
December 31, 1996, and the probable remaining minimum insurance reimbursement
is included in accounts receivable. As of December 31, 1996 and February 24,
1997, the Company had received approximately $9.8 million and $11.2 million,
respectively, under its insurance coverage as reimbursement for costs
incurred and paid by the Company associated with the spill. Management
believes that it is probable that this matter, including final reimbursement,
will be resolved in 1997 and that its previous accruals are adequate.
13. Quarterly financial data (unaudited)
The following is a tabulation of unaudited quarterly operating results
for 1996 and 1995 (in thousands, except for per share data).
Operating Gross Net Net Income
1996 Revenues Profit Income Per Share
First Quarter $ 12,145 $ 6,825 $ 3,861 $ .18
Second Quarter 13,219 7,820 4,398 .20
Third Quarter 13,433 7,063 4,012 .18
Fourth Quarter 16,394 8,958 5,275 .24
------- ------- ------- ----
$ 55,191 $ 30,666 $ 17,546 $ .80
======= ======= ======= ====
1995
First Quarter $ 10,445 $ 3,872 $ 2,210 $ .10
Second Quarter 12,436 5,933 2,876 .13
Third Quarter 12,172 5,688 3,374 .16
Fourth Quarter 10,732 3,394 3,743 .17
------- ------- ------- ----
$ 45,785 $ 18,887 $ 12,203 $ .56
======= ======= ======= ====
34
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, 1996. 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.
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, 1996, 1995
and 1994, and changes in such quantities during each of the years then ended
were as follows (in thousands):
1996 1995 1994
Oil Gas Oil Gas Oil Gas
Mbbls Mmcf Mbbls Mmcf Mbbls Mmcf
Proved developed
and undeveloped
reserves:
Beginning of year 77,071 5,983 75,996 6,530 72,078 5,476
Revision of previous
estimates 739 (810) 5,266 803 6,002 1,847
Production (3,491) (491) (3,277) (611) (3,250) (793)
Sale of reserves
in place - - (1,698) (739) - -
Purchase of reserves
in place 27,017 - 784 - 1,166 -
------- ----- ------ ----- ------ -----
End of year 101,336 4,682 77,071 5,983 75,996 6,530
======= ===== ====== ===== ====== =====
Proved developed reserves:
Beginning of year 62,856 3,380 62,718 4,727 62,261 4,810
======= ===== ====== ===== ====== =====
End of year 76,358 2,608 62,856 3,380 62,718 4,727
======= ===== ====== ===== ====== =====
35
BERRY PETROLEUM COMPANY
Supplemental Information About Oil & Gas Producing Activities
(Unaudited)(Cont'd)
Standardized measure of discounted future net cash flows from estimated
production of proved oil and gas reserves (in thousands):
The standardized measure has been prepared assuming year-end sales
prices adjusted for fixed and determinable contractual price changes, current
costs and statutory income tax rates previously legislated, 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.
1996 1995 1994
Future cash inflows $ 1,875,373 $ 1,039,150 $ 960,412
Future production and
development costs (429,879) (311,955) (317,735)
Future income tax expenses (495,412) (245,416) (213,225)
--------- --------- ---------
Future net cash flows 950,082 481,779 429,452
10% annual discount for estimated
timing of cash flows (529,523) (273,478) (248,499)
--------- --------- ---------
Standardized measure of discounted
future net cash flows $ 420,559 $ 208,301 $ 180,953
========= ========= =========
Pre-tax standardized measure
of discounted future net
cash flows $ 634,579 $ 308,370 $ 263,890
========= ========= =========
Average sales prices at December 31:
Oil ($/Bbl) $ 18.37 $ 13.39 $ 12.49
Gas ($/Mcf) $ 3.02 $ 1.45 $ 1.78
Changes in standardized measure of discounted future net cash flows from
proved oil and gas reserves (in thousands):
1996 1995 1994
Standardized measure - beginning
of year $ 208,301 $ 180,953 $ 36,626
--------- --------- ---------
Sales of oil and gas produced,
net of production costs (37,677) (27,509) (18,227)
Revisions to estimates of
proved reserves:
Net changes in sales prices and
production costs 170,529 41,726 194,099
Revisions of previous
quantity estimates 4,020 23,584 24,315
Change in estimated future
development costs (19,294) (14,234) (5,470)
Extensions, discoveries and improved
recovery less related costs - - -
Purchases of reserves in place 171,456 2,316 3,815
Sale of reserves in place - (8,645) -
Development costs incurred during
the period 9,305 14,034 4,678
Accretion of discount 30,837 2,639 4,602
Income taxes (101,936) (13,126) (68,416)
Other (14,982) 6,563 4,931
--------- --------- ---------
Net increase 212,258 27,348 144,327
--------- --------- ---------
Standardized measure -
end of year $ 420,559 $ 208,301 $ 180,953
========= ========= =========
36
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.
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.
37
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
A Form 8-K was filed on December 2, 1996 to report an Item 2 -
Acquisition of Assets. The Form 8-K was filed to report the
acquisition on November 19, 1996 of the Tannehill assets for $25.5 million.
No financial statements were filed with this Form 8-K, however,
summary financial statements and pro forma information were filed on
January 30, 1997 with a Form 8-K/A.
A Form 8-K was filed on December 17, 1996 to report an Item 2 -
Acquisition of Assets. The Form 8-K was filed to report the acquisition
on December 13, 1996 of the Formax assets for $49.5 million. No financial
statements were filed with this Form 8-K, however, summary financial
statements and pro forma information were filed on February 21, 1997
with a Form 8-K/A.
A Form 8-K was filed on December 19, 1996 to report an Item 6 -
Resignation of Registrant's Chairman of the Board of Directors
effective March 21, 1997.
A Form 8-K/A was filed on March 4, 1997 to amend the original Form 8-K
filed on December 19, 1996 to change the resignation of a director to an
Item 5 - Other Event as no disagreement or dispute existed.
A Form 8-K was filed on December 18, 1996 to report an Item 5 - Other
Event. The Form 8-K was filed to report the Company entering into a
$150 million unsecured three-year revolving credit facility agreement with
NationsBank of Texas.
A Form 8-K/A was filed on January 30, 1997 to amend the original
Form 8-K filed on December 2, 1996 to report the Tannehill acquisition,
to update the Form 8-K to include the financial statements and pro forma
financial information.
A Form 8-K/A was filed on February 21, 1997 to amend the original Form
8-K filed on December 17, 1996 to report the Formax acquisition,
to update the Form 8-K to include the financial statements and pro forma
financial information.
A Form 8-K was filed on January 23, 1997 to report an Item 5 - Other
Event. The Form 8-K was filed to report a settlement with the state
and federal government for the civil damages and penalties relating to the
December 1993 oil pipeline release at the Company's Montalvo field in
Ventura County, California.
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
(filed as Exhibit 10.7 to the Annual Report on Form 10-K
for the year ended December 31, 1990, File No. 1-9735)
10.2* Salary Continuation Agreement dated as of March 20, 1987, as
amended August 28, 1987, by and between Registrant and
Jerry V. Hoffman (filed as Exhibit 10.11 to the Registration
Statement on Form S-1 filed on June 7, 1989, File No. 33-29165)
10.3* 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)
10.4* 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)
10.5* 1987 Nonstatutory Stock Option Plan and 1987 Stock Appreciation
Rights Plan as amended March 18, 1988 (filed as Exhibit 10.14
in Registrant's Registration Statement on Form S-8 filed on July
28, 1988, File No. 33-23326)
10.6* Service Contract by and between Registrant and Pride Petroleum
Services, Inc. dated November 1, 1989 (filed as Exhibit 10.23
to the Registrant's Annual Report on Form 10-K for the year
ended December 31, 1989, File No. 0-11708)
10.7* 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)
10.8* Standard Offer #2 Power Purchase Agreement dated May 1984, as
amended by and between Registrant and Pacific Gas and Electric
Company (filed as Exhibit 10.8 in Registrant's Annual
Report on Form 10-K for the year ended December 31, 1995,
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, Inc., a
California corporation (filed as Exhibit 10.1 in Registrant's
Form 8-K filed on December 2, 1996, File No. 1-9735)
10.10* 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)
10.11* 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)
39
Exhibits (cont'd)
Exhibit No. Description of Exhibit Page
10.12* 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)
10.13* 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)
10.14 Standard Offer #2 Power Purchase Agreement dated May 1984 43
by and between Registrant's predecessor and Pacific Gas and
Electric Company.
10.15 Standard Offer #1 Power Purchase Agreement dated 129
January 16, 1997, by and between Registrant and
Pacific Gas and Electric Company.
10.16 Warrant Certificate dated November 14, 1996, 211
by and between Registrant and Tannehill Oil Company.
23.1 Consent of Coopers & Lybrand L.L.P. 220
23.2 Consent of DeGolyer and MacNaughton 221
27. ** Financial Data Schedule 222
99.1 Undertaking for Form S-8 Registration Statements 223
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
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 21, 1997.
BERRY PETROLEUM COMPANY
/s/ JERRY V. HOFFMAN /s/ RALPH J. GOEHRING /s/ DONALD A. DALE
JERRY V. HOFFMAN RALPH J. GOEHRING DONALD A. DALE
President and Chief Chief Financial Officer Controller (Principal
Executive Officer (Principal Financial Officer) Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities on the dates so indicated.
Name Office Date
/s/ Jerry V. Hoffman Chairman of the Board, March 21, 1997
Jerry V. Hoffman President & Chief
Executive Officer
/s/ Benton Bejach Director March 21, 1997
Benton Bejach
/s/ William F. Berry Director March 21, 1997
William F. Berry
/s/ Gerry A. Biller Director March 21, 1997
Gerry A. Biller
/s/ Ralph B. Busch, III Director March 21, 1997
Ralph B. Busch, III
/s/ William E. Bush,Jr. Director March 21, 1997
William E. Bush, Jr.
/s/ William B. Charles Director March 21, 1997
William B. Charles
/s/ Richard F. Downs Director March 21, 1997
Richard F. Downs
/s/ John A. Hagg Director March 21, 1997
John A. Hagg
/s/Thomas J. Jamieson Director March 21, 1997
Thomas J. Jamieson
/s/ Roger G. Martin Director March 21, 1997
Roger G. Martin