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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, 1998
Commission file number 1-9735
BERRY PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 77-0079387
(State of incorporation or (I.R.S. Employer Identification Number)
organization)
28700 Hovey Hills Road
Taft, California 93268
(Address of principal executive offices, including zip code)
Registrant's telephone number, including area code: (661) 769-8811
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Class A Common Stock, $.01 par value New York Stock Exchange
including associated stock purchase rights)
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
As of February 19, 1999, the registrant had 21,109,717 shares of Class A
Common Stock outstanding and the aggregate market value of the voting stock
held by nonaffiliates was approximately $136,057,000. This calculation is
based on the closing price of the shares on the New York Stock Exchange on
February 19, 1999 of $9 5/8. The registrant also had 898,892 shares of
Class B Stock outstanding on February 19, 1999, 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.
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BERRY PETROLEUM COMPANY
TABLE OF CONTENTS
PART I
Items 1
and 2. Business and Properties . . . . . . . . . . . . . . . . . . . . 3
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Oil Marketing . . . . . . . . . . . . . . . . . . . . . . . . . 4
Steaming Operations . . . . . . . . . . . . . . . . . . . . . . 5
Environmental and Other Regulations . . . . . . . . . . . . . . 6
Competition . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Oil and Gas Properties . . . . . . . . . . . . . . . . . . . . 7
Development . . . . . . . . . . . . . . . . . . . . . . . . . 7
Exploration . . . . . . . . . . . . . . . . . . . . . . . . . 8
Enhanced Oil Recovery Tax Credits . . . . . . . . . . . . . . . 9
Oil and Gas Reserves . . . . . . . . . . . . . . . . . . . . . 9
Production . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Acreage and Wells . . . . . . . . . . . . . . . . . . . . . . .10
Drilling Activity . . . . . . . . . . . . . . . . . . . . . . .10
Title and Insurance . . . . . . . . . . . . . . . . . . . . . .10
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . .11
Item 4. Submission of Matters to a Vote of Security Holders . . . . . .11
Executive Officers . . . . . . . . . . . . . . . . . . . . . .11
PART II
Item 5. Market for the Registrant's Common Equity
and Related Shareholder Matters . . . . . . . . . . . . . . .12
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . .13
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations . . . . . . . .14
Item 8. Financial Statements and Supplementary Data . . . . . . . . .19
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . . . . .38
PART III
Item 10. Directors and Executive Officers of the Registrant . . . . . .38
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . .38
Item 12. Security Ownership of Certain Beneficial Owners and
Management . . . . . . . . . . . . . . . . . . . . . . . . . .38
Item 13. Certain Relationships and Related Transactions . . . . . . . .38
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K . . . . . . . . . . . . . . . . . . . . .38
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PART I
Items 1 and 2. Business and Properties
General
Berry Petroleum Company, ("Berry" or "Company"), is an independent energy
company engaged in the production, development, acquisition, exploitation,
exploration and marketing of crude oil and natural gas. The Company was
incorporated in Delaware in 1985 and has been a publicly traded company
since 1987. Currently, Berry's principal reserves and producing properties
are located in Kern, Los Angeles and Ventura Counties in California.
Information contained in this report on Form 10-K reflects the business of
the Company during the year ended December 31, 1998. 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 and proved
reserves, the Company will compete to acquire oil and gas properties with
primarily proved reserves with exploitation potential and will focus on the
further development of its existing properties by application of enhanced oil
recovery (EOR) methods, developmental drilling, well completions and remedial
work. 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 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, 1998, the Company's estimated proved reserves were 92.6
million barrels of oil equivalent, (BOE), of which 99.3% is crude oil. The
majority of these proved reserves are owned in fee. Substantially all of the
Company's reserves as of December 31, 1998 were located in California with 94%
and 6% of total reserves in Kern and Ventura Counties, respectively. The
Company's reserves have a long life, in excess of 20 years, which is primarily
a result of the Company's strong position in heavy crude oil (the Company's
properties in the Midway-Sunset field average 13 degree API gravity and the
Montalvo field averages 16 degree API gravity). Production in 1998 was
4.4 million BOE, down 3% from 1997 production of 4.6 million BOE. For the
five years 1994 through 1998, the Company's average reserve replacement rate
was 202% at a cost of $3.19 per BOE.
Acquisitions
South Midway-Sunset
Effective August 1, 1998, Berry purchased two leases and two fee
properties totaling 280 acres with estimated reserves of up to 1.3 million
barrels of 13 degree gravity crude oil for $3.1 million. The properties are
adjacent to Berry's other core South Midway-Sunset properties and averaged
208 net barrels of oil per day (BPD) for the Company in 1998. The acquisition
also included the assignment of a steam contract which delivers a minimum of
2,000 barrels of steam per day (BSPD) for use in production. The Company
paid for this acquisition out of cash flow.
Placerita
On December 23, 1998, the Company announced that it entered into an
agreement to purchase the Placerita oilfield in Los Angeles County for $35
million. By agreement, the Company took over operations as of January 1,
1999. The Company completed the transaction on February 12, 1999. None of
the 1998 operating data nor year end reserves of the property are included in
the Company's 1998 year end financial statements or tabular data presented in
this report. This acquisition is very important to the Company's future
operations. These properties are currently producing approximately 2,800 net
BPD of 13 degree gravity crude oil. Berry estimates the proved reserves to
be approximately 20
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million barrels, which at closing gave the Company approximately 112 million
barrels versus 92.6 million BOE at December 31, 1998. In addition, the
acquisition included a 42 megawatt cogeneration facility which provides
steam for use in the enhanced oil recovery methods utilized to produce the
oil. On January 21, 1999, the Company amended its existing credit agreement
and increased its borrowing base to $110 million. The Company increased its
borrowings in January 1999 by approximately $32 million to finance this
acquisition.
Operations
Berry operates all of its principal oil producing properties. Berry
utilizes primary recovery methods at its Montalvo field. The Midway-Sunset and
Placerita fields contain predominantly heavy crude oil which requires heat,
supplied in the form of steam, that is injected into the oil producing
formations to reduce the oil viscosity which improves the mobility of the oil
in flowing to the well-bore for production. Berry utilizes primary and
cyclic steaming recovery methods in the Midway-Sunset field and steam-drive
in the Placerita field. 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 either
metered through Lease Automatic Custody Transfer (LACT) units and transferred
into crude oil pipelines owned by other companies or, as in the case of the
Placerita field, loaded on trucks. The point-of-sale is usually the LACT unit
or truck loading facility.
Revenues
The percentage of revenues by source for the prior three years is as
follows:
1998 1997 1996
Sales of oil and gas 100% 97% 97%
Interest and other income -%(1) 3% 3%
(1) less than 1%
Oil Marketing
The world and California markets for crude oil remained extremely
depressed throughout 1998 and into 1999. In October 1997, world crude oil
prices began a decline to the lowest levels in decades. Several factors have
caused an imbalance in supply of and demand for crude oil that may continue
to keep crude oil prices low in the near future.
The collective Asian economies have been responsible for a large part of
the world's growth in energy demand during the past few years. In 1998, the
Asian economies faltered and, as a result, growth in demand for crude oil from
this region has been reduced. In addition to this reduction in world demand,
Iraq has increased its crude oil production under the United Nations "food for
oil" sales program from approximately .5 million BPD in 1997 to a current level
of 2.5 million BPD. Also, the Organization of Petroleum Exporting Countries
(OPEC) agreed in late 1997 to an increase in production quotas that resulted in
a further increase in world crude supplies. Until current crude oil supply and
demand conditions change, crude oil prices are likely to remain at low levels.
For example, since early 1998, OPEC has implemented production quota reductions
among members, in addition to other exporting nations voluntarily reducing
production, in an attempt to reduce supply and increase world crude oil prices.
To date, this attempt has not resulted in higher crude oil prices.
On a positive note, the crude price differential between lighter crude
oils and California's heavy crude oil remains at historically low levels.
The lower light/heavy crude price differential is due to the decline in
competing Alaska North Slope (ANS) production, lifting of the export ban on
ANS crude oil, and past expansion of deep conversion capacity in West Coast
refineries designed to increase the use and improve the refining economics of
heavy crude oil. In addition, unlike other parts of the world where crude
oil inventories are at excessive levels, crude oil inventories on the West
Coast remain at or near average historical levels. Also, California is still
experiencing strong gasoline and asphalt demand.
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Another factor that will positively impact the California heavy crude
market is the current construction of a new 132 mile crude oil pipeline, the
Pacific Pipeline, that will deliver unblended San Joaquin Valley heavy crude
oil into the Los Angeles refining market. The Pacific Pipeline is insulated
and provides another transportation outlet for San Joaquin Valley heavy crude
oil without requiring lighter crude oil volumes as transportation blendstock.
The construction of the Pacific Pipeline has been completed and the pipeline
has been put into operation as of March 1999.
Berry competitively markets its crude oil production to competing buyers
including independent marketing, pipeline and integrated oil companies.
Management does not believe that the loss of any single customer or contract
would materially affect its business. The Company sells its oil and gas
production under both short-term and long-term contracts up to 18 months in
duration, whereby the Company agrees to deliver certain volumes of crude oil
to pipeline delivery points at the Company's properties. These contracts
provide for the sale of crude oil at current market prices. At various times
in the past, the Company has been able, through its marketing efforts, to
obtain crude oil price premiums, the level of which depends upon current
market conditions. From time to time, the Company also enters into crude oil
and natural gas hedge contracts depending on various factors, including
Management's view of future crude oil and natural gas prices, and the
Company's future financial commitments. The Company currently has a
bracketed zero cost collar hedge contract with an independent refiner for
3,000 BPD based upon California 13 degree gravity heavy crude oil posted
price. This contract expires on December 31, 1999. The hedging activities
contributed $.50 to the average price received for the Company's crude oil in
1998 and resulted in a net cost to the Company of less than $.01 per barrel
in 1997. Berry's 1998 average heavy crude oil sales price was $9.02 per
barrel, down $5.68 per barrel, or 39%, from $14.70 in 1997.
Steaming Operations
At December 31, 1998, approximately 94% of the Company's proved reserves,
or 87 million barrels, consisted of heavy crude oil produced from depths
averaging less than 2,000'. With the acquisition of the Placerita properties
in February 1999, approximately 95% of the proved reserves, or 107 million
barrels, consisted of heavy crude oil. The depths of the Placerita wells
range from 1,100' to 2,800', averaging 1,800'. The Company, in achieving its
goal of being a low cost heavy oil producer, has focused on reducing its
steam cost by the purchase of two gas-fired cogeneration facilities in 1995
and 1996, and the Placerita cogeneration facility in early 1999. Steam
generation from these facilities is more efficient than conventional steam
generators, as both steam and electricity are produced from the same natural
gas fuel supply. The proceeds received from the sale of electricity offset
a large portion of the cost of producing steam and are reported as a reduction
to operating costs in the Company's financial statements.
For its South Midway-Sunset properties, the Company's current steam
production is generated by its 38 and 18 megawatt cogeneration facilities
(approximately 18,500 BSPD) and, as needed, from conventional steam generators.
In addition, the Company made modifications to use the duct-firing capability
of its 38 megawatt facility to produce up to an additional 4,500 BSPD
available for delivery to its South Midway-Sunset properties. In August 1998,
the Company acquired a steam contract from an on-site, non-owned cogeneration
facility for a minimum delivery of 2,000 BSPD for use in the Company's
operations. Conventional steam generators are used by the Company at its
South Midway-Sunset properties as required to maintain current production
levels, to economically produce additional crude oil and as emergency back-up
steam generation to the cogeneration facilities. Due to low oil prices, the
Company temporarily shut down the duct-firing steam capacity in early 1998
and reduced the utilization of conventional steam generators at the South
Midway-Sunset field to reduce costs and improve cash flow. The Company
started increasing the volume of steam injected in this field in late 1998,
and in early 1999 restored duct-firing, offsetting some conventional steam
generation. On its North Midway-Sunset properties, the Company relies solely
on conventional steam generators for its steam requirements. On its Placerita
properties, the Company generates approximately 13,500 BSPD from its 42
megawatt cogeneration facility, acquires another 3,000 BSPD from a third
party cogeneration facility and has available another 6,000 BSPD from
conventional steam generators. The Company has ample productive steam
capacity for its requirements at all three core areas.
The Company's two cogeneration facilities in the South Midway-Sunset field
sold electricity to a large California-based utility under Standard Offer #2
(SO2) contracts in 1996. The SO2 contract for the 38 megawatt facility expired
on January 16, 1997, while the contract for the 18 megawatt facility does not
expire until January 31, 2002. The SO2
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contract for the 38 megawatt facility was replaced by a 15-year Standard Offer
#1 (SO1) contract effective January 16, 1997, which resulted in lower
electricity revenues than under the previous SO2 contract. However, under the
SO1 contract, the Company will continue to receive Short Run Avoided Cost
pricing plus a portion of the proceeds related to available capacity that was
received in prior years. The 42 megawatt facility (Placerita), which has two
separate 21 megawatt gas fired turbines, has two SO2 contracts; one which
expires in May 2002, and the other in March 2009. The electricity from this
facility is sold to a different California-based utility than the other
contracts. Deregulation of the electricity generation market in California
may have a positive or negative impact on the Company's future electricity
revenues. The Company believes, at a minimum, continued steam generation
from cogeneration facilities will be significantly more efficient and cost
effective than conventional steam generators.
The Company has physical access to gas pipelines, such as the Kern
River/El Paso and Southern California Gas Company systems, to transport its
gas purchases required for steam generation. Prior to February 1997, natural
gas purchases for the 38 megawatt cogeneration facility were subject to a
long-term gas transportation agreement which required the Company to pay
above-market transportation rates for a substantial portion of the facility's
gas requirements. The expiration of this contract resulted in substantial
reductions in gas transportation costs beginning in 1997. Currently, none of
the Company's cogeneration facilities are subject to any long-term gas
transportation agreements.
Environmental and Other Regulations
The operations of Berry are affected by federal, state, regional and
local laws and regulations, including laws governing allowable rates of
production, well spacing, air emissions, water discharges, endangered
species, marketing, pricing, taxes, land use restrictions and other laws
relating to the petroleum industry. Berry is further affected by changes
in such laws and by constantly changing administrative regulations.
The Company's oil and gas operations and properties are subject to
numerous federal, state and local laws and regulations relating to
environmental protection. These laws and regulations govern, among other
things, the amounts and types of substances and materials that may be
released into the environment, the issuance of permits in connection
with drilling, production and electricity generation activities, the
discharge and disposition of waste materials, the reclamation and abandonment
of wells and facility sites and the remediation of contaminated sites. In
addition, these laws and regulations may impose substantial liabilities for
the Company's failure to comply with them or for any contamination resulting
from the Company's operations.
Berry has established policies and procedures for continuing compliance
with environmental laws and regulations affecting its production. The costs
incurred to comply with these laws and regulations are inextricably connected
to normal operating expenses such that the Company is unable to separate the
expenses related to environmental matters; however, the Company does not
believe any such additional future expenses are material to its financial
position or results of operations.
Although environmental requirements do have a substantial impact upon the
energy industry, generally these requirements do not appear to affect the
Company any differently, or to any greater or lesser extent, than other
companies in California and in the domestic industry as a whole. Berry
believes that compliance with environmental laws and regulations will not
have a material adverse effect on the Company's operations or financial
condition but there can be no assurances that changes in or additions to
laws or regulations regarding the protection of the environment will not
have such an impact in the future.
Berry maintains insurance coverage which it believes is customary in the
industry, although it is not fully insured against all environmental risks.
The Company is not aware of any environmental claims existing as of
December 31, 1998, which would have a material impact upon the Company's
financial position or results of operations.
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Competition
The oil and gas industry is highly competitive. As an independent
producer, the Company does not own any refining or retail outlets and,
therefore, it has little control over the price it receives for its crude oil.
As such, higher costs, fees and taxes assessed at the producer level cannot
necessarily be passed on to the Company's customers. In acquisition
activities, significant competition exists as both integrated and
independent companies and individual producers and operators are active
bidders for desirable oil and gas properties. Although many of these
competitors have greater financial and other resources than the Company,
Management believes that 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, 1998, the Company had 88 full-time employees. In
conjunction with the acquisition of the Placerita properties, the Company
increased its full-time employees to 103 as of February 19, 1999.
Oil and Gas Properties
Development
South Midway-Sunset - Berry owns and operates working interests in twenty-
two properties consisting of 2,010 acres located in the South Midway-Sunset
field. The Company estimates these properties account for approximately 84% of
the Company's proved oil and gas reserves and approximately 85% of its current
daily production. Fourteen of these properties are owned in fee. The wells
produce from an average depth of approximately 1200'. These properties rely
on thermal EOR methods, primarily cyclic steaming.
During 1998, the primary focus in this field was directed at the continued
integration and further development of the Formax and Tannehill properties,
acquired in 1996, into the Company's operations. Of the 17 new wells drilled
in 1998 in this area, 10 were drilled on these recently acquired properties.
In addition, during 1998, the Company drilled a total of 3 horizontal wells
in this field and completed 35 workovers on existing wells. The Company's
objectives related to using this developing technology were to improve
ultimate recovery of original oil-in-place, reduce the development and
operating costs of the properties and accelerate production. In 1999, the
Company plans to drill an additional 8 development wells in this field, 3 of
which will be horizontal wells.
North Midway-Sunset - Berry owns and operates approximately 1,975 acres
in the North Midway-Sunset field which account for approximately 10% of the
Company's proved oil and gas reserves and 8% of daily production. These
properties also rely on thermal EOR methods, primarily cyclic steaming.
Berry's interests consist of four fee properties comprising 1,009 acres and
nine leases comprising 966 acres. These wells produce from an average depth
of approximately 1200'.
During 1998, the Company drilled 3 development wells to maintain
productive capacity and develop proved reserves and one exploitation well to
begin delineation of the diatomite accumulation in the Antelope Zone on top
of the Fairfield anticline. At current crude oil price levels, the Company
has no plans to drill additional development wells in this area. The Company
has, however, budgeted one well to continue delineation of the Antelope Shale
and other diatomaceous intervals.
Montalvo - Berry owns a 100% working interest in six leases, comprising
8,563 acres, in Ventura County, California comprising the Montalvo field. The
State of California is the lessor for two of the six leases. The Company
estimates current proved reserves from Montalvo account for approximately 6% of
Berry's proved oil and gas reserves. Total production from these leases
represents approximately 7% of Berry's total current daily oil and gas
production. The wells produce from an average depth of approximately 12,500'.
No new wells were drilled in 1998 or 1997.
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Placerita - On February 12, 1999, Berry acquired the Placerita oilfield
from a large California oil producer. The property consists of six leases
(three are federal leases) and two fee properties totaling approximately 700
acres. The average depth of the wells is approximately 1,800'. These
properties rely on thermal EOR methods, primarily steam drive.
The following is a summary of capital expenditures incurred during 1998
and 1997 and projected capital expenditures for 1999:
CAPITAL EXPENDITURES SUMMARY
(in thousands)
1999(1) 1998 1997
(Projected)
South Midway-Sunset Field
New wells $ 1,615 $ 2,886 $ 10,078
Remedials/workovers 370 767 1,695
Facilities 380 1,028 3,180
Cogeneration facilities (2) 2,300 623 208
------ ------ -------
4,665 5,304 15,161
------ ------ -------
North Midway-Sunset Field
New wells 175 826 1,719
Remedials/workovers - 57 251
Facilities - 45 336
------ ------ -------
175 928 2,306
------ ------ -------
Montalvo
Remedials/workovers - 117 -
Facilities - 108 -
------ ------ -------
- 225 -
------ ------ -------
Other
412 524 1,130
------ ------ -------
Totals $ 5,252 $ 6,981 $ 18,597
====== ====== =======
(1) Budgeted capital expenditures may be adjusted for numerous reasons
including, but not limited to, results of drilling and oil price levels. See
the Future Developments section of Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations.
(2) Principally relates to a major turnaround required on the 38 megawatt
facility.
Exploration
The Company did not participate in the drilling of any exploratory wells
in 1998 or 1997 and has none budgeted for 1999. Although the Company has
significantly reduced its exploration program since 1994 to concentrate on
growth through development of existing assets and strategic acquisitions, the
Company may investigate and pursue a focused exploration program in the future.
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Enhanced Oil Recovery Tax Credits
In 1990, President Bush signed into law the Revenue Reconciliation Act of
1990 which included a tax credit for certain costs associated with extracting
high-cost marginal oil which utilizes at least one of nine designated
"enhanced" or tertiary recovery methods. Cyclic steam and steam drive
recovery methods, which Berry utilizes extensively, are qualifying EOR
methods. In 1996, California conformed to the federal law thus, on a
combined basis, the Company is able to achieve credits approximating 12% of
its qualifying costs. The credit is earned for a qualified EOR project by
investing in one of three types of expenditures: (1) drilling new wells,
(2) adding facilities that are integrally related to qualified EOR production,
or (3) utilizing a tertiary injectant, such as steam, to produce oil. This
credit is significant in reducing the Company's income tax liabilities and
effective tax rate.
Oil and Gas Reserves
The Company continued to engage DeGolyer and MacNaughton (D&M) to estimate
the proved oil and gas reserves and the future net revenues to be derived from
properties of the Company for the year ended December 31, 1998. D&M is an
independent oil and gas consulting firm located in Dallas, Texas. In preparing
their reports, D&M reviewed and examined geologic, economic, engineering and
other data provided by the Company considered applicable to each reserve
determination. They also examined the reasonableness of certain economic
assumptions regarding forecasted operating and development costs and recovery
rates in light of the economic environment on December 31, 1998. For the
Company's operated properties, these reserve estimates are filed annually with
the U.S. Department of Energy. Refer to the Supplemental Information About
Oil & Gas Producing Activities (Unaudited) for the Company's oil and gas
reserve disclosures.
Production
The following table sets forth certain information regarding production
for the years ended December 31, as indicated:
1998 1997 1996
Net annual production(1):
Oil (Mbbls) 4,359 4,503 3,491
Gas (Mmcf) 245 282 491
Total equivalent barrels(2) 4,399 4,550 3,573
Average sales price:
Oil (per bbl) $ 9.02 $ 14.70 $ 15.42
Gas (per mcf) 2.64 2.68 1.99
Per BOE 9.05 14.71 15.36
Average production cost (per BOE) 4.05 4.92 4.92
(1) Net production represents that owned by Berry and produced to its interest,
less royalty and other similar interests.
(2) Equivalent oil and gas information is at a ratio of 6 thousand cubic feet
(mcf) of natural gas to 1 barrel (bbl) of oil.
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Acreage and Wells
At December 31, 1998, the Company's properties accounted for the following
developed and undeveloped acres:
Developed Acres Undeveloped Acres
Gross Net Gross Net
California 6,573 6,572 6,846 6,846
Other 360 42 - -
------ ------ ------ ------
6,933 6,614 6,846 6,846
====== ====== ====== ======
Gross acres represent acres in which Berry has a working interest; net
acres represent Berry's aggregate working interests in the gross acres.
Berry currently has 2,119 gross oil wells (2,113 net) and 4 gross gas
wells (3.1 net). Gross wells represent the total number of wells in which
Berry has a working interest. Net wells represent the number of gross wells
multiplied by the percentages of the working interests owned by Berry. One
or more completions in the same bore hole are counted as one well. Any well
in which one of the multiple completions is an oil completion is classified
as an oil well.
Drilling Activity
The following table sets forth certain information regarding Berry's
drilling activities for the periods indicated:
1998 1997 1996
Gross Net Gross Net Gross Net
Exploratory wells drilled:
Productive - - - - - -
Dry(1) - - - - - -
Development wells drilled:
Productive 20 20 89 88.9 46 45.1
Dry(1) 1 1 1 1 3 2.1
Total wells drilled:
Productive 20 20 89 88.9 46 45.1
Dry(1) 1 1 1 1 3 2.1
(1) A dry well is a well found to be incapable of producing either oil or
gas in sufficient quantities to justify completion as an oil or gas well
Title and Insurance
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 on all of its properties, the Company believes it
has satisfactory title to its properties, subject to such exceptions as the
Company believes are customary and usual in the oil and gas industry and
which the Company believes will not materially impair its ability to recover
the proved oil and gas reserves or to obtain the resulting economic benefits.
The oil and gas business can be hazardous, involving unforeseen
circumstances such as blowouts or environmental damage. Although it is not
insured against all risks, the Company maintains a comprehensive insurance
program to address the hazards inherent in the oil and gas business.
10
11
Item 3. Legal Proceedings
The Company is a party to certain lawsuits arising in the ordinary course
of business. Although the outcome of these lawsuits cannot be predicted with
certainty, the Company does not expect such matters to have a material adverse
effect on the financial statements of the Company.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Executive Officers
Listed below are the names, ages (as of December 31, 1998) and positions
of the executive officers of Berry and their business experience during at
least the past five years. All officers of the Company are appointed in May
of each year at an organizational meeting of the Board of Directors. There
are no family relationships between any executive officer and members of the
Board of Directors.
JERRY V. HOFFMAN, 49, 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 has held a variety of other positions with the Company and its
predecessors since February 1985.
GEORGE T. CRAWFORD, 38, Manager of Production, since January 4, 1999. Mr.
Crawford, a petroleum engineer, was previously the Production Engineering
Supervisor for ARCO Western Energy, a subsidiary of Atlantic Richfield Corp.
(ARCO). Mr. Crawford was employed by ARCO from 1989 to 1998 in numerous
engineering and operational assignments including Production Engineering
Supervisor, Planning and Evaluation Consultant and Operations Superintendent.
DONALD A. DALE, 52, Controller since December 1985. Mr. Dale was the
Controller for the Company's predecessor from September 1985 to December 1985.
RALPH J. GOEHRING, 42, Senior Vice President and Chief Financial Officer.
Mr. Goehring has been Senior Vice President since April 1997, Chief Financial
Officer since March 1992 and was Manager of Taxation from September 1987
until March 1992. Mr. Goehring is also the Assistant Secretary for the
Company.
KENNETH A. OLSON, 43, Corporate Secretary since December 1985 and
Treasurer since August 1988. Mr. Olson has held a variety of other positions
with the Company and its predecessors since July 1985.
BRIAN L. REHKOPF, 51, Manager of Engineering since September 1997, joined
the Company's engineering department in June 1997. Mr. Rehkopf, a registered
petroleum engineer, was previously a Vice President and Asset Manager with
ARCO Western Energy, a subsidiary of ARCO since 1992 and an Operations
Engineering Supervisor with ARCO from 1988 to 1992.
MICHAEL R. STARZER, 37, 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.
11
12
PART II
Item 5. Market for the Registrant's Common Equity and Related Shareholder
Matters
Shares of Class A Common Stock (Common Stock) and Class B Stock, referred
to collectively as the "Capital Stock", are each entitled to one vote and 95%
of one vote, respectively. Each share of Class B Stock is entitled to a
$1.00 per share preference in the event of liquidation or dissolution.
Further, each share of Class B Stock is convertible into one share of Common
Stock at the option of the holder.
In 1989, the Company adopted a Shareholder Rights Agreement and declared a
dividend distribution of one such Right for each outstanding share of Capital
Stock on December 22, 1989. Each share of Capital Stock issued after December
22, 1989 includes one Right. The Rights expire on December 8, 1999. See Note 7
of Notes to the Financial Statements.
In conjunction with the acquisition of Tannehill in 1996, the Company
issued a Warrant Certificate to the beneficial owners of Tannehill Oil Company.
This Warrant authorizes the purchase of 100,000 shares of Berry Petroleum
Company Class A Common Stock until November 8, 2003 at $14.06 per share. All
the warrants are currently outstanding and the underlying shares will not be
registered under the Securities Act of 1933.
Berry's Class A Common Stock is listed on the New York Stock Exchange
under the symbol "BRY". The Class B Stock is not publicly traded. The market
data and dividends for 1998 and 1997 are shown below:
1998 1997
Price Range Dividends Price Range Dividends
High Low per Share High Low per Share
First Quarter $ 17 1/2 $ 13 3/4 $.10 $ 15 7/8 $ 14 $.10
Second Quarter 15 3/8 13 .10 19 13 7/8 .10
Third Quarter 13 13/16 10 1/2 .10 20 1/2 16 3/16 .10
Fourth Quarter 14 1/4 11 1/2 .10 21 3/8 17 .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
19, 1999, December 31, 1998 and December 31, 1997 was $9 5/8, $14 3/16
and $17 7/16, respectively.
The number of holders of record of the Company's Common Stock was 885 (and
approximately 3,000 street name shareholders) as of February 19, 1999. There
was one Class B Stockholder of record as of February 19, 1999.
The Company paid cash dividends for many years prior to the roll-up of the
various Berry companies into Berry Petroleum Company on December 16, 1985.
Since Berry's formation, the Company has paid dividends on its Common Stock
for eight consecutive semi-annual periods through September 1989 and for
37 consecutive quarters through December 31, 1998. The Company intends
to continue the payment of dividends, although future dividend payments will
depend upon the Company's level of earnings, operating cash flow, capital
commitments, financial covenants and other relevant factors.
At December 31, 1998, dividends declared on 4,033,150 shares of certain
Common Stock are restricted, whereby 37.5% of the dividends declared on these
shares are paid by the Company to the surviving member of a group of
individuals, the B group, for as long as this remaining member shall live.
12
13
Item 6. Selected Financial Data
The following table sets forth certain financial information with respect
to the Company and is qualified in its entirety by reference to the historical
financial statements and notes thereto of the Company included in Item 8,
"Financial Statements and Supplementary Data." The statement of operations and
balance sheet data included in this table for each of the five years in the
period ended December 31, 1998 were derived from the audited financial
statements and the accompanying notes to those financial statements
(in thousands, except per share and per barrel data):
1998 1997 1996 1995 1994
Statement of Operations
Data:
Sales of oil and gas $ 39,858 $ 67,172 $ 55,264 $ 45,773 $ 39,451
Operating costs 17,828 22,407 17,587 18,264 21,224
General and
administrative
expenses (G&A) 3,975 5,907 4,820 4,578 5,118
Depreciation,
depletion &
amortization
(DD&A) 10,080 10,138 7,323 6,847 7,270
Net income (loss) 3,879 19,260 17,546 12,203 (1,129)
Basic net income
(loss) per share .18 .88 .80 .56 (.05)
Weighted average number
of shares outstanding 22,007 21,976 21,939 21,932 21,932
Balance Sheet Data:
Working capital $ 9,081 $ 11,499 $ 7,850 $ 36,506 $ 38,273
Total assets 173,804 177,724 176,403 117,722 118,254
Long-term debt 30,000 32,000 36,000 - -
Shareholders' equity 106,924 111,871 101,009 92,060 88,632
Cash dividends per
Share .40 .40 .40 .40 .40
Operating Data:
Cash flow from
Operations 19,924 31,401 29,182 17,070 14,579
Capital expenditures
(excluding
acquisitions) 6,981 18,597 15,616 14,569 5,911
Property acquisitions 2,991 - 69,330 503 1,023
Per BOE:
Sales price $ 9.05 $ 14.71 $ 15.36 $ 13.48 $ 11.60
Operating costs 4.05 4.92 4.92 5.41 6.28
G&A .90 1.30 1.35 1.35 1.51
----- ----- ----- ----- -----
Cash flow 4.10 8.49 9.09 6.72 3.81
DD&A 2.29 2.23 2.05 2.03 2.15
----- ----- ----- ----- -----
Operating income $ 1.81 $ 6.26 $ 7.04 $ 4.69 $ 1.66
===== ===== ===== ===== =====
Production (BOE) 4,399 4,550 3,573 3,379 3,382
Proved Reserves
Information:
Total BOE 92,609 101,043 102,116 78,068 77,084
Present value (PV10)
of estimated future
cash flow before
income taxes $113,811 $376,459 $634,579 $308,370 $263,890
Year end BOE price
for PV10 purposes 7.05 12.19 18.37 13.39 12.49
Other:
Return on average
shareholders' equity 3.5% 18.1% 18.2% 13.6% (1.2)%
Return on average
total assets 2.2% 10.9% 13.3% 10.5% (0.9)%
Total debt/total debt
plus equity 21.9% 22.2% 29.8% N/A N/A
13
14
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion provides information on the results of operations
for each of the three years ended December 31, 1998 and the financial condition,
liquidity and capital resources as of December 31, 1998. The financial
statements and the notes thereto contain detailed information that should be
referred to in conjunction with this discussion.
The profitability of the Company's operations in any particular accounting
period will be directly related to the average realized prices of oil and gas
sold, the type and volume of oil and gas produced and the results of
acquisition, development, exploitation and exploration activities. The average
realized prices for oil and gas will fluctuate from one period to another due
to world and regional market conditions and other factors. The aggregate
amount of oil and gas produced may fluctuate based on the success of
development and exploitation of oil and gas reserves pursuant to current
reservoir management. Production rates, steam costs net of electricity
revenue, labor, maintenance expenses and production taxes are expected to be
the principal influences on operating costs. Accordingly, the results of
operations of the Company may fluctuate from period to period based on the
foregoing principal factors, among others.
Results of Operations
Net income for 1998 was $3.9 million, down $15.4 million, or 80%, from
$19.3 million in 1997 and $13.6 million, or 78% from $17.5 million in 1996.
For the fourth quarter of 1998, net income was a loss of ($1.1) million, down
$5.8 million and $6.4 million from $4.7 million in the fourth quarter of 1997
and $5.3 million in the fourth quarter of 1996, respectively. Although the
Company maintained good cost discipline in 1998, profitability decreased due
to a very negative pricing environment for crude oil.
The following table presents certain operating data for the years ended
December 31, 1998, 1997 and 1996:
1998 1997 1996
Net production - BOE per day 12,053 12,465 9,762
Per BOE:
Average sales price $ 9.05 $ 14.71 $ 15.36
Operating costs* 3.46 4.24 4.44
Production taxes .59 .68 .48
Total operating costs 4.05 4.92 4.92
DD&A 2.29 2.23 2.05
G&A .90 1.30 1.35
* Excluding production taxes.
Operating income from producing operations was $12.3 million in 1998, down
$22.7 million and $18.4 million, respectively, from $35 million in 1997 and
$30.7 million in 1996 due to the significant decline in oil prices in 1998
compared to the prior years.
The average sales price/BOE received in 1998 was $9.05, or 38% below the
average of $14.71 in 1997 and 41% lower than the average of $15.36 for 1996.
World oil prices declined sharply in early 1998. The average posting for
Midway-Sunset crude oil which began the year at $12.19 had reached $6.50 by
March 16, 1998. Although postings rebounded slightly for short periods during
the balance of 1998, the average posted price during December 1998 was
only $6.53 and the average posted price has remained at very low levels in 1999.
Oil and gas production of 12,053 BOE/day in 1998 was 412 BOE/day, or 3% lower
than production of 12,465 BOE/day in 1997, but 2,291 BOE/day, or
24% higher than 1996 production of 9,762 BOE/day. The decrease in production
from 1997 was primarily related to the reduction of steam injection and reduced
capital expenditures on the Company's Midway-Sunset properties. This
reduction was necessitated by the poor crude oil pricing environment. The
increases in production compared to 1996 were primarily related to production
from and development of acquisitions made in the latter part of 1996.
14
15
The Company continued to achieve excellent cost control in 1998.
Operating costs for the year averaged $4.05/BOE, down 18% from $4.92/BOE in
both 1997 and 1996. Many factors contributed to the positive results achieved
in this area. The Company's Management correctly interpreted the decline in
oil prices as a long-term event and moved quickly to reduce costs and protect
the cash flow of the Company. An across-the-board 10% salary reduction was
implemented and selected personnel reductions were made. Steam production
from higher cost sources such as conventional steam generation and cogeneration
plant duct firing was eliminated or significantly reduced. The number of well
service rigs was reduced and some low producing wells were shut-in. In
addition, production taxes began to decline in the second half of 1998 due to
lower oil property valuations. Also, the price of cogeneration steam was
lower than 1997 primarily because of lower gas prices.
DD&A/BOE increased to $2.29 in 1998, up 3% from $2.23 in 1997 and 12% from
$2.05 in 1996. The increase is due to higher depreciation related to additional
facilities and a higher basis related to the cumulative effect of recent capital
budgets.
The Company purchased certain properties in the Midway-Sunset field in the
third quarter of 1998 for $3.1 million in cash. The acquisition included four
producing properties and a steam purchase contract from an on-site, non-owned
cogeneration plant. These properties currently produce approximately 210 BPD
and the Company believes that additional development opportunities on these
properties are available.
On December 31, 1998, the Company recorded a $1.8 million pre-tax
impairment charge relating to non-producing properties in Kern County due to
the low year end oil price of $7.05/barrel.
Included in the 1998 gain/(loss) on sale of assets is a charge of $.76
million which represents the write-off of a receivable and related legal
expenses incurred to collect amounts owed from the 1995 sale of its Rincon
properties. Included in the 1997 gain/(loss) on sale of assets is a gain of
$1.0 million resulting from the sale of certain non-core properties in that
year.
General
Interest expense in 1998 was $1.9 million, down from $2.3 million in 1997,
but up significantly from $.2 million in 1996. The Company did not capitalize
interest expense in any of these periods. The reduction from 1997 was due to
the reduction in debt in both 1997 and 1998 and generally lower borrowing rates
in 1998. The Company did not have long-term debt until the borrowings were
made pursuant to the acquisitions made in the latter part of 1996. Interest
and dividend income was $.8 million in 1998, up from $.6 million in 1997, but
down from $2.1 million in 1996.
G&A was $4.0 million in 1998, down 32% and 17%, respectively, from $5.9
million in 1997 and $4.8 million in 1996. On a per BOE basis, G&A decreased to
$.90 from $1.30 in 1997 and $1.35 in 1996. In light of the severe market
conditions faced by the Company in early 1998, several steps were initiated to
reduce and control costs. An across-the-board 10% salary reduction, with
certain members of Management taking even higher reductions, was implemented
in March of 1998. Simultaneously, reductions were made in the number of
employees. These two factors accounted for approximately $1.0 million of the
G&A savings as compared to 1997. The salaries were reinstated effective
January 1, 1999. In addition, the Company experienced lower compensation
related to the exercise of stock options by employees and directors and also
lower medical claims.
The Company's effective income tax rate in 1998 was 9%, down from 32% and
36% in 1997 and 1996, respectively. The lower rate in 1998 was due primarily
to the impact of certain tax benefits, primarily EOR credits and percentage
depletion, applied against lower income in 1998 compared to 1997 and 1996. The
Company expects that its effective rate will remain significantly below the 32%
rate it achieved in 1997 if the current low oil price environment continues.
15
16
In December 1997, the Company adopted Statement of Financial Accounting
Standards (SFAS) No. 128, "Earnings Per Share". As required by this new
standard, the Company reports two earnings per share amounts, basic net income
per share and diluted net income per share. Basic net income per share is
computed by dividing income available to common shareholders (the numerator) by
the weighted average number of common shares outstanding (the denominator).
The computation of diluted net income per share is similar to the computation
of basic net income per share except that the denominator is increased to
include the dilutive effect of the additional common shares that would have
been outstanding if all convertible securities had been converted to common
shares during the period.
Also, during 1997 the Company adopted the provisions of the American
Institute of Certified Public Accountants Statement of Position (SOP) 96-1,
"Environmental Remediation Liabilities" and SFAS No. 125, "Accounting for
Transfer and Servicing of Financial Assets and Extinguishments of Liabilities."
The adoption of these two pronouncements had no material impact on the
financial statements of the Company.
During 1996, the Company implemented the disclosure requirements of SFAS
No. 123, "Accounting for Stock Based Compensation." This statement sets forth
alternative standards for recognition of the cost of stock-based compensation
and requires that a Company's financial statements include certain disclosures
about stock-based employee compensation arrangements regardless of the method
used to account for them. As allowed in this statement, the Company continues
to apply Accounting Principles Board Opinion (APB) No. 25, "Accounting for
Stock Issued to Employees," and related interpretations in recording
compensation related to its plans. The supplemental disclosure requirements
and further information related to the Company's stock option plans are
presented in Note 9 to the Company's financial statements.
Financial Condition, Liquidity and Capital Resources
Working capital as of December 31, 1998 was $9.1 million, down from $11.5
million at December 31, 1997 and up from $7.9 million at December 31, 1996.
Cash flow from operations in 1998 was $19.9 million, down 37% and 32%,
respectively, from $31.4 million in 1997 and $29.2 million in 1996. The
decrease in cash flow in 1998 was primarily due to a 38% decrease in the
average sales price of heavy crude oil and a 3% decrease in production.
Working capital decreased in 1998 from 1997, primarily because internal cash
flows paid a portion, but not all, of the cost of $7.0 million in capital
expenditures, the payment of $8.8 million in dividends, the retirement of
$2.0 million in long-term debt and the cost of property acquisitions of
$3.0 million. The Company's 1998 capital budget included the drilling of
21 development wells, remedial work on a number of other wells and $1.3 million
in improvements to surface facilities.
On December 1, 1996, the Company established a $150 million unsecured
revolving credit facility with NationsBank, N.A. As of December 31, 1998, the
borrowing base was $35 million. On January 21, 1999, the Company amended its
credit agreement and established a new borrowing base of $110 million and
included two additional banks in its syndication. The primary purpose of this
amendment was to increase the borrowing base and to fund the Placerita
acquisition. The Company is carrying $62 million in long-term debt under this
credit facility as of February 19, 1999.
The total proved reserves at December 31, 1998 were 92.6 million BOE, down
from 101 million BOE at December 31, 1997 and 102.1 million BOE at December 31,
1996. The decrease in 1998 was primarily related to production of 4.4 million
barrels and the reduction of 5 million barrels deemed uneconomic at the
December 31, 1998 oil price of $7.05/barrel, partially offset by the
acquisition of approximately 1 million barrels of reserves in properties
adjacent to the Company's South Midway-Sunset properties.
The Company's present value of estimated future net cash flows before
income taxes, discounted at 10%, was $114 million at December 31, 1998, down
substantially from $376 million and $635 million at December 31, 1997 and
December 31, 1996, respectively. This decline is also primarily related to the
decline in oil prices. The values were based on year end oil prices of $7.05,
$12.19 and $18.37 per BOE for 1998, 1997 and 1996, respectively.
16
17
Year 2000
In 1997, the Company began a review of its computer hardware, software
applications and process control equipment with embedded semiconductor chips to
determine which components, if any, would not function correctly in the years
2000 and beyond. In the third quarter of 1998, the Company created a Year 2000
(Y2k) team to monitor the results of the review on an ongoing basis to better
ensure that the Company's operations will not experience any material adverse
effects when the year 2000 arrives.
As part of the review, started in 1997, the Company determined that its
accounting software would have to be modified or replaced. The Company has
identified new software that is represented to be Y2k compliant. Two
modules were replaced in the first half of 1998. The remaining modules are
scheduled to be replaced during the first nine months of 1999. The total cost
of the software and hardware purchased to complete the installation is
estimated to be approximately $.6 million. If, for some reason, the software
cannot be purchased and installed by the year 2000, the Company intends to
modify its existing software to handle Y2k. These modifications would be
made by the Company's in-house information systems personnel. The Company
has evaluated all of its other software, which is predominantly purchased
from third party providers, and determined that they are substantially Y2k
compliant as of the end of 1998.
The Company has performed an evaluation of its computer hardware and
determined that with only a few minor exceptions, it is Y2k compliant at this
time. Minor upgrades were completed on some of the equipment to make them
compliant at no material cost to the Company.
The Company has made inquiries to the operator of the Company's two
cogeneration facilities to ensure that all equipment is Y2k compliant. These
facilities provide over two-thirds of the Company's steam, which is necessary
to produce the Company's heavy oil reserves. The Company has been informed
by the operator that the facilities are Y2k compliant at this time. If, by
the year 2000, the cogeneration facilities are not compliant, it could have
a material adverse effect on the Company's production volumes and results of
operations. If the plants were shut down, the Company would fire its
conventional generators, which would result in a lower volume of steam at a
higher cost to the Company. However, the Company believes such action will
not be necessary and is confident that the facilities will be compliant when
the year 2000 arrives. Facilities and equipment at the Placerita properties
acquired in February 1999 and the non-owned cogeneration facilities which
provide additional steam to the Placerita and South Midway-Sunset properties
will be evaluated during the first half of 1999.
The Company's customers are predominantly major oil companies or large
independent refiners. If any of these customers were not Y2k compliant by the
end of 1999 and could not buy the Company's crude oil, it could have a
material impact on the Company's operations. The Company's operations could
also be impacted if the pipeline companies that transport the crude oil or if
any of the utility or critical service providers were not Y2k compliant and
could not provide their products and services. However, Management anticipates
that these companies will be ready and, therefore, the Company's operations
will not be materially impacted when the year 2000 arrives. The Company has
communicated with the financial institutions that are business partners of the
Company. It is anticipated that they will be Y2k compliant by the year 2000
resulting in no material impact to the Company. If any of the Company's
other business partners are not Y2k compliant by the year 2000, Management does
not believe it will have a material impact on the Company's operations.
17
18
Future Developments
On February 12, 1999, the Company completed the acquisition of the
Placerita oilfield producing properties and a 42 megawatt duel-turbine
cogeneration facility from a large California oil producer for $35 million.
The producing properties contain approximately 20 million barrels of proven
reserves of 13 degree gravity crude oil. Production on the properties is
enhanced primarily through the use of steam drive methods. The power from
both turbines at the cogeneration facility is sold under SO2 contracts.
This facility generates economical steam available for the property and
lowers operating costs substantially. The Company began operating the
property on December 31, 1998, and continues to integrate the operations.
Due to the continuing historic low crude oil prices received by the
Company in early 1999, the Company is operating under an austere capital
budget. In addition, the Company estimates that it has shut-in approximately
550 BPD of production due to poor economics. As oil prices improve, it is
likely that the Company will return to production these shut-in wells and may
increase its capital budget as cash flow allows.
Deregulation of the electricity generation market in California may have a
positive or negative impact on the Company's future steam costs as electricity
prices somewhat de-couple from natural gas prices. As of December 31, 1998,
the Company's electricity price received for sales from the two cogeneration
plants owned by the Company correlates directly with natural gas prices.
Therefore, our net steam costs are fairly consistent between quarters and
years. In the future, electricity prices will be determined by not only the
cost of natural gas, but also the cost of coal, hydroelectric, nuclear and
other sources of fuel. In addition, power consumption demand may make
electricity prices more volatile than in the past.
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,
gas and electricity, environmental risks, drilling and operating risks,
uncertainties about the estimates of reserves, Y2k non-compliance by the
vendors, customers, the Company, etc. and government regulation.
18
19
Item 8. Financial Statements and Supplementary Data
BERRY PETROLEUM COMPANY
Index to Financial Statements and
Supplementary Data
Page
Report of PricewaterhouseCoopers LLP, Independent Accountants . . . . . 20
Balance Sheets at December 31, 1998 and 1997 . . . . . . . . . . . . . 21
Statements of Operations for the
Years Ended December 31, 1998, 1997 and 1996 . . . . . . . . . . . . . 22
Statements of Shareholders' Equity for the
Years Ended December 31, 1998, 1997 and 1996 . . . . . . . . . . . . . 23
Statements of Cash Flows for the
Years Ended December 31, 1998, 1997 and 1996 . . . . . . . . . . . . . 24
Notes to the Financial Statements . . . . . . . . . . . . . . . . . . . 25
Supplemental Information About Oil & Gas Producing Activities. . . . . . 36
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.
19
20
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders and Board of Directors
Berry Petroleum Company
In our opinion, the accompanying balance sheets and the related statements of
income and retained earnings and of cash flows present fairly, in all material
respects, the financial position of Berry Petroleum Company (the "Company") at
December 31, 1998 and 1997, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used and significant
estimates made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for the
opinion expressed above.
s/s PRICEWATERHOUSECOOPERS LLP
February 12, 1999
Los Angeles, California
20
21
BERRY PETROLEUM COMPANY
Balance Sheets
December 31, 1998 and 1997
(In Thousands, Except Share Information)
1998 1997
ASSETS
Current assets:
Cash and cash equivalents $ 7,058 $ 7,756
Short-term investments available
for sale 710 718
Accounts receivable 5,495 8,990
Prepaid expenses and other 4,049 1,979
------- -------
Total current assets 17,312 19,443
Oil and gas properties (successful efforts
basis), buildings and equipment, net 155,571 157,441
Other assets 921 840
------- -------
$ 173,804 $ 177,724
======= =======
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 5,491 $ 4,432
Accrued liabilities 2,108 2,459
Federal and state income taxes payable 632 1,053
------- -------
Total current liabilities 8,231 7,944
Long-term debt 30,000 32,000
Deferred income taxes 28,649 25,909
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; 21,109,729 shares issued
and outstanding (21,094,494 in 1997) 211 211
Class B Stock, 1,500,000 shares authorized;
898,892 shares issued and outstanding
(liquidation preference of $899) 9 9
Capital in excess of par value 53,400 53,422
Retained earnings 53,304 58,229
------- -------
Total shareholders' equity 106,924 111,871
------- -------
$ 173,804 $ 177,724
======= =======
The accompanying notes are an integral part of these financial statements.
21
22
BERRY PETROLEUM COMPANY
Statements of Operations
Years ended December 31, 1998, 1997 and 1996
(In Thousands, Except Per Share Data)
1998 1997 1996
Revenues:
Sales of oil and gas $ 39,858 $ 67,172 $ 55,264
Interest and dividend income 805 643 2,081
Gain/(loss) on sale of assets (716) 1,093 -
Other income (expense), net (48) 87 (72)
------- ------- -------
39,899 68,995 57,273
------- ------- -------
Expenses:
Operating costs 17,828 22,407 17,658
Depreciation, depletion & amortization 10,080 10,138 7,323
Interest expense 1,939 2,302 178
Impairment of properties 1,827 - -
General and administrative 3,975 5,907 4,820
------- ------- -------
35,649 40,754 29,979
------- ------- -------
Income before income taxes 4,250 28,241 27,294
Provision for income taxes 371 8,981 9,748
------- ------- -------
Net income $ 3,879 $ 19,260 $ 17,546
======= ======= =======
Basic net income per share $ .18 $ .88 $ .80
======= ======= =======
Diluted net income per share $ .18 $ .87 $ .80
======= ======= =======
Weighted average number of shares of
capital stock outstanding (used to
calculate basic net income per share) 22,007 21,976 21,939
Effect of dilutive securities:
Stock options 25 173 25
Other 5 16 -
------- ------- -------
Weighted average number of shares of
capital stock used to calculate
diluted net income per share 22,037 22,165 21,964
======= ======= =======
The accompanying notes are an integral part of these financial statements.
22
23
BERRY PETROLEUM COMPANY
Statements of Shareholders' Equity
Years Ended December 31, 1998, 1997 and 1996
(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, 1996 $ 210 $ 9 $ 52,850 $ 38,991 $ 92,060
Stock options
expired - - (1) - (1)
Stock options
Exercised - - 180 - 180
Cash dividends
Declared -
$.40 per share - - - (8,776) (8,776)
Net income - - - 17,546 17,546
------ ------ ------- ------- -------
Balances at
December 31, 1996 210 9 53,029 47,761 101,009
Stock options
exercised 1 - 393 - 394
Cash dividends
declared -
$.40 per share - - - (8,792) (8,792)
Net income - - - 19,260 19,260
------ ------ ------- ------- -------
Balances at
December 31, 1997 211 9 53,422 58,229 111,871
Stock options
Exercised - - (58) - (58)
Deferred director
fees - stock
compensation - - 36 - 36
Cash dividends
declared -
$.40 per share - - - (8,804) (8,804)
Net income - - - 3,879 3,879
------ ------ ------- ------- -------
Balances at
December 31, 1998 $ 211 $ 9 $ 53,400 $ 53,304 $ 106,924
====== ====== ======= ======= =======
The accompanying notes are an integral part of these financial statements.
23
24
BERRY PETROLEUM COMPANY
Statements of Cash Flows
Years Ended December 31, 1998, 1997 and 1996
(In Thousands)
1998 1997 1996
Cash flows from operating activities:
Net income $ 3,879 $ 19,260 $ 17,546
Depreciation, depletion and
Amortization 10,080 10,138 7,323
Gain on sale of assets (55) (1,093) -
Impairment of properties 1,827 - -
Increase in deferred income tax
liability 2,740 4,917 4,024
Other, net (260) (302) (258)
------- ------- -------
Net working capital provided by
operating activities 18,211 32,920 28,635
Decrease (increase) in current
assets other than cash, cash
equivalents and short-term
investments 1,425 2,039 (2,262)
Increase (decrease) in current
liabilities other than notes
payable 288 (3,558) 2,809
------- ------- -------
Net cash provided by operating
Activities 19,924 31,401 29,182
------- ------- -------
Cash flows from investing activities:
Capital expenditures, excluding
property acquisitions (6,981) (18,597) (15,616)
Property acquisitions (2,991) - (69,330)
Proceeds from sale of assets 350 1,892 352
Purchase of short-term investments - (14) (710)
Maturities of short-term investments 8 - 15,700
Restricted cash deposit - 2,570 (2,570)
Other, net (240) (50) (100)
------- ------- -------
Net cash used in investing activities (9,854) (14,199) (72,274)
------- ------- -------
Cash flows from financing activities:
Proceeds from issuance of long-term
debt - 3,000 36,000
Proceeds from issuance of short-term
notes payable - - 6,900
Payment of long-term debt (2,000) (7,000) -
Payment of short-term notes payable - (6,900) -
Dividends paid (8,804) (8,792) (8,776)
Other, net 36 276 179
------- ------- -------
Net cash provided by (used in)
financing activities (10,768) (19,416) 34,303
------- ------- -------
Net decrease in cash and cash
Equivalents (698) (2,214) (8,789)
Cash and cash equivalents at beginning
of year 7,756 9,970 18,759
------- ------- -------
Cash and cash equivalents at
end of year $ 7,058 $ 7,756 $ 9,970
======= ======= =======
Supplemental disclosures of cash
flow information:
Interest paid $ 1,924 $ 2,319 $ -
======= ======= =======
Income taxes paid $ 270 $ 4,280 $ 4,709
======= ======= =======
The accompanying notes are an integral part of these financial statements.
24
25
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
1. General
The Company is an independent energy company engaged in the production,
development, acquisition, exploitation, exploration and marketing of crude oil
and natural gas. Substantially all of the Company's oil and gas reserves are
located in California. Approximately 99% of the Company's production is crude
oil, which is principally sold to other oil companies for processing in
refineries located in California.
The preparation of financial statements in conformity with generally
accepted accounting principles requires Management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
2. Summary of significant accounting policies
Cash and cash equivalents
The Company considers all highly liquid investments purchased with a
remaining maturity of three months or less to be cash equivalents.
Short-term investments
All short-term investments are classified as available for sale. Short-
term investments consist principally of United States treasury notes and
corporate notes with remaining maturities of more than three months at date of
acquisition. Such investments are stated at cost, which approximates market.
The Company utilizes specific identification in computing realized gains and
losses on investments sold.
Oil and gas properties, buildings and equipment
The Company accounts for its oil and gas exploration and development costs
using the successful efforts method. Under this method, costs to acquire and
develop proved reserves and to drill and complete exploratory wells that find
proved reserves are capitalized and depleted over the remaining life of the
reserves using the units-of-production method. Exploratory dry hole costs and
other exploratory costs, including geological and geophysical costs, are
charged to expense when incurred. The costs of carrying and retaining unproved
properties are also expensed when incurred.
Depletion of oil and gas producing properties is computed using the units-
of-production method. Depreciation of lease and well equipment is computed
using the units-of-production method or on a straight-line basis over estimated
useful lives ranging from 10 to 20 years. The estimated costs, net of salvage
value, of plugging and abandoning oil and gas wells and related facilities are
accrued using the units-of-production method and are taken into account in
determining DD&A expense. Buildings and equipment are recorded at cost.
Depreciation is provided on a straight-line basis over estimated useful lives
ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for
machinery and equipment. Assets are grouped at the field level and if it is
determined that the book value of long-lived assets cannot be recovered by
estimated future undiscounted cash flows, they will be written down to fair
value. When assets are sold, the applicable costs and accumulated depreciation
and depletion are removed from the accounts and any gain or loss is included in
income. Expenditures for maintenance and repairs are expensed as incurred.
25
26
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
2. Summary of significant accounting policies (cont'd)
Hedging
The Company has periodically entered into bracketed zero cost collar hedge
contracts on a portion of its crude oil production with a California refiner to
protect the Company's revenues from potential price declines. Any revenues
received or costs incurred related to this hedging activity are reflected in
sales of oil and gas of the Company.
Steam Costs
The costs of producing steam are recorded as an operating expense of the
Company. Proceeds received from the sale of electricity produced by its
cogeneration plants are reported as a reduction to operating costs in the
Company's financial statements.
Stock-Based Compensation
During 1996, the Company implemented the disclosure requirements of
Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for
Stock-Based Compensation." This statement sets forth alternative
standards for recognition of the cost of stock-based compensation and requires
that a Company's financial statements include certain disclosures about stock-
based employee compensation arrangements regardless of the method used to
account for them. As allowed in this statement, the Company continues to apply
Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued
to Employees," and related interpretations in recording compensation
related to its plans. The supplemental disclosure requirements and further
information related to the Company's stock option plans are presented in Note 9
to the Company's financial statements.
Income Taxes
Income taxes are provided based on the liability method of accounting
pursuant to SFAS No. 109, "Accounting for Income Taxes." The provision for
income taxes is based on pre-tax financial accounting income. Deferred tax
assets and liabilities are recognized for the future expected tax consequences
of temporary differences between income tax and financial reporting, and
principally relate to differences in the tax basis of assets and liabilities
and their reported amounts using enacted tax rates in effect for the year in
which differences are expected to reverse. If it is more likely than not that
some portion or all of a deferred tax asset will not be realized, a valuation
allowance is recognized.
Earnings Per Share
In December 1997, the Company adopted SFAS No. 128, "Earnings per Share."
As required by this new standard, the Company reports two earnings per share
amounts, basic net income and diluted net income per share. Basic net income
per share is computed by dividing income available to common shareholders (the
numerator) by the weighted average number of common shares outstanding (the
denominator). The computation of diluted net income per share is similar to
the computation of basic net income per share except that the denominator is
increased to include the dilutive effect of the additional common shares that
would have been outstanding if all convertible securities had been converted to
common shares during the period. Comparative earnings per share data for prior
periods presented has been restated to conform to the new standard.
Reclassifications
Certain reclassifications have been made to the 1997 and 1996 financial
statements to conform with the 1998 presentation.
26
27
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
3. Fair value of financial instruments
Financial instruments consist of cash and short-term investments, whose
carrying amounts are not materially different from their fair values because of
the short maturity of those instruments. Cash equivalents consist principally
of commercial paper investments. Cash equivalents of $6.9 million and $6.2
million at December 31, 1998 and 1997, respectively, are stated at cost, which
approximates market.
The Company's short-term investments available for sale at December 31,
1998 and 1997 consist of one United States treasury note. All of the
short-term investments at December 31, 1998 mature in less than one year.
The carrying value of the Company's long-term debt, which was incurred in
1996, is assumed to approximate its fair value since it is carried at current
interest rates. For the three years ended December 31, 1998, realized and
unrealized gains and losses were insignificant to the financial statements.
United States treasury notes with an aggregate market value of $.6 million
are pledged as collateral to the California State Lands Commission as a
performance bond on the Company's Montalvo properties.
To protect the Company's revenues from potential price declines, the
Company entered into a bracketed zero cost collar hedge contract with a
California refiner covering 3,000 BPD of its crude oil production. The posted
price of the Company's 13 degree API gravity crude oil was used as the basis
for the hedge. The current contract expires on December 31, 1999.
4. Concentration of Credit Risks
The Company sells oil, gas and natural gas liquids to pipelines,
refineries and major oil companies. Credit is extended based on an
evaluation of the customer's financial condition. For the three years ended
December 31, 1998, the Company has experienced no credit losses on the sale
of oil, gas and natural gas liquids.
The Company places its temporary cash investments with high quality
financial institutions and limits the amount of credit exposure to any one
financial institution. For the three years ended December 31, 1998, the
Company has not incurred losses related to these investments.
The following summarizes the accounts receivable balances at December 31,
1998 and 1997 and sales activity with significant customers for each of the
years ended December 31, 1998, 1997 and 1996 (in thousands):
Sales
Accounts Receivable For the Year Ended December 31,
Customer December 31, 1998 December 31, 1997 1998 1997 1996
A $ 794 $ 1,681 $ 12,409 $ 19,482 $ 14,478
B 601 1,587 10,785 12,875 -
C 435 1,812 7,281 23,804 23,067
D 454 15 6,282 7,119 10,982
------- ------- ------- ------- -------
$ 2,284 $ 5,095 $ 36,757 $ 63,280 $ 48,527
======= ======= ======= ======= =======
27
28
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):
1998 1997
Oil and gas:
Proved properties:
Producing properties, including
intangible drilling costs $ 133,372 $ 128,453
Lease and well equipment 93,637 92,461
------- -------
227,009 220,914
Less accumulated depreciation,
depletion and amortization 73,577 65,828
------- -------
153,432 155,086
------- -------
Commercial and other:
Land 170 151
Buildings and improvements 4,007 4,034
Machinery and equipment 3,775 3,653
------- -------
7,952 7,838
Less accumulated depreciation 5,813 5,483
------- -------
2,139 2,355
------- -------
$ 155,571 $ 157,441
======= =======
The following sets forth costs incurred for oil and gas property acquisition,
exploration and development activities, whether capitalized or expensed (in
thousands):
1998 1997 1996
Acquisition of properties(1) $ 2,991 $ - $ 69,330
Exploration - - 40
Development(2) 6,896 18,172 15,689
------- ------- -------
$ 9,887 $ 18,172 $ 85,059
======= ======= =======
(1) Excludes cogeneration facility costs and includes certain closing and
consultant costs related to the acquisitions.
(2) Includes cogeneration facilities.
The Company completed two significant acquisitions (Tannehill and Formax) in
1996 for a combined purchase price of approximately $75 million, including the
purchase of an 18 megawatt cogeneration facility. In 1998, the Company
completed one acquisition consisting of minerals and a steam contract. These
properties are in the Company's core South Midway-Sunset producing area. These
acquisitions had proved reserves of approximately 28 million barrels upon
acquisition.
28
29
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
5. Oil and gas properties, buildings and equipment (cont'd)
Results of operations from oil and gas producing and exploration activities
The results of operations from oil and gas producing and exploration
activities (excluding corporate overhead and interest costs) for the three
years ended December 31 are as follows (in thousands):
1998 1997 1996
Sales to unaffiliated parties $ 39,858 $ 67,172 $ 55,264
Production costs (17,828) (22,407) (17,658)
Depreciation, depletion and
Amortization (9,686) (9,731) (6,868)
------- ------- -------
12,344 35,034 30,738
Income tax expenses (3,223) (10,870) (10,230)
------- ------- -------
Results of operations from
producing and exploration
activities $ 9,121 $ 24,164 $ 20,508
======= ======= =======
6. Debt obligations 1998 1997
Long-term debt for the years
ended December 31 (in thousands):
Revolving bank facility $ 30,000 $ 32,000
======= =======
At December 31, 1998, Berry had a $150 million unsecured three-year
revolving credit facility with NationsBank N.A. As of December 31, 1997, the
borrowing base was $40 million and the principal amount outstanding was $32
million. As of January 23, 1998, the borrowing base was reduced to $35
million. On January 21, 1999, the Company amended its existing credit
agreement with the bank primarily to increase the borrowing base to $110
million and add two additional banks to its syndication. In addition, the
facility has been revised to be a five-year bullet loan. The maximum amount
available is subject to an annual redetermination of the borrowing base in
accordance with the lender's customary procedures and practices. Both parties
have bilateral rights to one additional redetermination each year. The
revolving period is scheduled to terminate on January 21, 2004. Interest on
amounts borrowed is charged at NationsBank base rate or at London Interbank
Offered Rates (LIBOR) plus 75 to 150 basis points, depending on the ratio of
outstanding credit to the borrowing base. The weighted average interest rate
on outstanding borrowings at December 31, 1998 was 6.02%. The Company pays a
commitment fee of 25 to 35 basis points on the available unused portion of
the commitment. The credit agreement contains other restrictive covenants as
defined in the agreement.
In conjunction with the purchase of Tannehill in November 1996, the
Company incurred $6.9 million in short-term notes, which were due and paid on
January 6, 1997.
29
30
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
7. Shareholders' equity
Shares of Class A Common Stock (Common Stock) and Class B Stock, referred
to collectively as the "Capital Stock", are each entitled to one vote and 95%
of one vote, respectively. Each share of Class B Stock is entitled to a
$1.00 per share preference in the event of liquidation or dissolution. Further,
each share of Class B Stock is convertible into one share of Common Stock at
the option of the holder.
In December 1989, the Company adopted a Shareholder Rights Agreement and
declared a dividend distribution of one Right for each outstanding share of
Capital Stock. Each Right, when exercisable, entitles the holder to purchase
one one-hundredth of a share of a Series A Junior Participating Preferred
Stock, or in certain cases other securities, for $38.00. The exercise price
and number of shares issuable are subject to adjustment to prevent dilution.
The Rights would become exercisable, unless earlier redeemed by the Company,
10 days following a public announcement that a person or group has acquired,
or obtained the right to acquire, 20% or more of the outstanding shares of
Common Stock or, 10 business days following the commencement of a tender or
exchange offer for such outstanding shares which would result in such person
or group acquiring 20% or more of the outstanding shares of Common Stock,
either event occurring without the prior consent of the Company.
The Rights will expire in December 1999 or may be redeemed by the Company
at $.01 per Right prior to that date unless they have theretofore become
exercisable. The Rights do not have voting or dividend rights, and until they
become exercisable, have no diluting effect on the earnings of the Company. A
total of 250,000 shares of the Company's Preferred Stock has been designated
Series A Junior Participating Preferred Stock and reserved for issuance upon
exercise of the Rights.
In conjunction with the acquisition of Tannehill, the Company issued a
Warrant Certificate to the beneficial owners of Tannehill Oil Company. This
Warrant authorizes the purchase of 100,000 shares of Berry Petroleum Company
Class A Common Stock until November 8, 2003 at $14.06 per share. All the
warrants are currently outstanding and the underlying shares will not be
registered under the Securities Act of 1933.
The Company issued 15,268, 47,621, and 13,932 shares in 1998, 1997 and
1996, respectively, through its stock option plans.
At December 31, 1998, dividends declared on 4,033,150 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.
30
31
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
8. Income taxes
The Provision for income taxes consists of the following (in thousands):
1998 1997 1996
Current:
Federal $ (716) $ 3,502 $ 3,519
State (881) 995 1,027
------ ------ ------
(1,597) 4,497 4,546
------ ------ ------
Deferred:
Federal 1,968 3,940 4,322
State - 544 880
------ ------ ------
1,968 4,484 5,202
------ ------ ------
Total $ 371 $ 8,981 $ 9,748
====== ====== ======
The current deferred tax assets and liabilities are offset and presented
as a single amount in the financial statements. Similarly, the noncurrent
deferred tax assets and liabilities are presented in the same manner. The
following table summarizes the components of the total deferred tax assets
and liabilities before such financial statement offsets. The components of
the net deferred tax liability consist of the following at December 31
(in thousands):
1998 1997
Deferred tax asset
Federal benefit of state taxes $ 1,514 $ 1,900
Credit/deduction carryforwards 2,481 1,440
Other, net (479) 415
------- -------
3,516 3,755
------- -------
Deferred tax liability
Depreciation and depletion (26,143) (24,069)
State taxes, net of federal benefit (4,545) (4,546)
Other, net (275) (619)
------- -------
(30,963) (29,234)
------- -------
Net deferred tax liability $ (27,447) $ (25,479)
======= =======
31
32
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
8. Income taxes (cont'd)
Reconciliation of the statutory federal income tax rate to the effective
income tax rate follows:
1998 1997 1996
Tax computed at statutory federal rate 34.0% 35.0% 35.0%
Asset acquisition/sale differences (3.0) - -
State income taxes, net of federal
Benefit 2.0 3.5 4.5
Tax credits (24.3) (7.6) (4.5)
Other - .9 .7
------ ------ ------
Effective tax rate 8.7% 31.8% 35.7%
====== ====== ======
The Company has $.3 million of loss carryforwards which may be utilized
in future years to reduce the Company's federal income taxes. These loss
carryforwards expire in the year 2000. The Company also has approximately
$3.0 million of federal and $1.6 million of state enhanced oil recovery (EOR)
tax credit carryforwards available to reduce future income taxes. The EOR
credits will expire in the years 2012 and 2013, if not previously utilized.
32
33
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
9. Stock option and stock appreciation rights plans
The Company has a 1987 Nonstatutory Stock Option Plan (the NSO Plan) and a
1987 Stock Appreciation Rights Plan (the SAR Plan). The NSO Plan provided for
the granting of options (Options) to purchase up to an aggregate of 700,000
shares of Common Stock. The SAR Plan originally authorized a maximum of
700,000 shares of Common Stock subject to stock appreciation rights (SARs).
Holders of SARs had the right upon exercise to receive a payment, payable at
the discretion of the Compensation Committee in cash or in shares of Common
Stock, equal to the amount by which the market price exceeds the Base Price
(as defined) with respect to the shares subject to such SARs on the date of
exercise. In December 1994, the Board of Directors adopted a resolution to
terminate the 1987 Stock Appreciation Rights Plan without utilizing the
307,860 SARs which were still available for issuance. The 1,120 outstanding
SARs at December 31, 1997 were exercised in early 1998. Total compensation
expense recognized for the SAR Plan was less than $100,000 in 1998, 1997 and
1996, respectively.
On December 2, 1994, the Board of Directors of the Company adopted the
Berry Petroleum Company 1994 Stock Option Plan which was restated and amended
in December 1997 (the 1994 Plan) and approved by the shareholders in May 1998.
The 1994 Plan provides for the granting of stock options to purchase up to an
aggregate of 2,000,000 shares of Common Stock. All Options, with the exception
of the formula grants to non-employee Directors, will be granted at the
discretion of the Compensation Committee of the Board of Directors. The term
of each Option may not exceed ten years from the date the Option is granted.
On December 4, 1998, December 5, 1997, June 2, 1997 and December 6, 1996,
434,000, 200,000, 40,000 and 480,000 Options, respectively, were issued to
certain key employees at an exercise price of $12.50, $19.375, $15.50
and $14.00 per share, respectively, which was the closing market price of the
Company's Class A Common Stock on the New York Stock Exchange on those dates.
The Options vest 25% per year for four years. The 1994 Plan also allows for
Option grants to the Board of Directors under a formula plan whereby
all non-employee Directors are eligible to receive 5,000 Options annually on
December 2 at the fair value on the date of grant. The Options granted to
the non-employee Directors vest immediately. Through the 1994 Plan, 45,000,
30,000 and 33,000 Options, respectively, were issued on December 2, 1998,
December 2, 1997 and 1996, (5,000 Options to each of the non-employee Directors
each year for 1998 and 3,000 for 1997 and 1996) at an exercise price of
$12.625, $18.9375 and $13.75 per share, respectively. In addition, 25,000
Options were granted on May 15, 1998 to the Non-employee Directors on
December 2, 1997 at an exercise price of $18.9375.
The Company applies APB No. 25 and related interpretations in accounting
for its stock option 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 the 1994 Plan was
$.04 million in 1998, $.5 million in 1997 and $.1 million in 1996.
Under SFAS No. 123, compensation cost would be recognized for the fair
value of the employee's option rights. The fair value of each option grant was
estimated on the date of grant using the Black-Scholes option-pricing model
with the following assumptions:
1998 1997 1996
Dividend - $/year $ .40 $ .40 $ .40
Expected option life-years 4 4 4
Volatility 28.13% 26.03% 24.97%
Risk-free interest rate 4.68% 5.48% 6.10%
33
34
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
9. Stock option and stock appreciation rights plans (cont'd)
Had compensation cost for the 1994 Plan been based upon the fair value at
the grant dates for awards under this plan consistent with the method of SFAS
No. 123, the Company's net income and earnings per share would have been
reduced to the pro forma amounts indicated below (in thousands, except per
share data):
1998 1997 1996
Net income as reported $ 3,879 $ 19,260 $ 17,546
Pro forma $ 3,244 $ 19,185 $ 17,387
Net income per share as reported $ .18 $ .88 $ .80
Pro forma $ .15 $ .87 $ .79
The following is a summary of stock-based compensation activity for the
years 1998, 1997 and 1996.
1998 1997 1996
Options SARs Options SARs Options SARs
Balance out-
standing,
January 1 924,429 1,120 861,229 9,200 431,141 39,740
Granted 504,000 - 270,000 - 513,000 -
Exercised (75,799) (1,120) (196,800) (8,080) (76,912) (30,540)
Canceled/
expired (125,000) - (10,000) - (6,000) -
--------- ------ ------- ------ ------- -------
Balance out-
standing,
December 31 1,227,630 - 924,429 1,120 861,229 9,200
========= ====== ======= ====== ======= =======
Balance exer-
cisable at
December 31 449,880 - 256,929 1,120 231,229 9,200
========= ====== ======= ====== ======= =======
Available for
future grant 681,800 - 60,800 - 320,800 -
========= ====== ======= ====== ======= =======
Exercise
price-
Range $ 9.80 $ 9.80 $ 9.80 $ 9.80 $ 9.80 $ 9.80
to 19.375 to 19.375 to 10.00 to 14.00 to 10.00
Weighted average
remaining
contractual
life (years) 9 - 9 1 9 2
Weighted average
fair value per
option granted
during
the year $ 2.82 $ 4.56 $ 3.22
Weighted average option exercise price information for the years 1998, 1997
and 1996 as follows:
1998 1997 1996
Outstanding at January 1 $ 14.71 $ 12.61 $ 10.52
Granted during the year $ 12.83 $ 18.75 $ 13.98
Exercised during the year $ 11.42 $ 11.03 $ 12.82
Expired during the year $ 14.34 $ 14.00 $ 10.69
Outstanding at December 31 $ 14.18 $ 14.71 $ 12.61
Exercisable at December 31 $ 14.17 $ 13.09 $ 11.02
34
35
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
10. Retirement Plan
The Company sponsors a defined contribution retirement or thrift plan
(401(k) Plan) to assist all employees in providing for retirement or other
future financial needs. Employee contributions (up to 6% of their earnings)
are matched by the Company dollar for dollar. Effective November 1, 1992, the
401(k) Plan was modified to provide for increased Company matching of employee
contributions whereby the monthly Company matching contributions will
range from 6% to 9% of eligible participating employee earnings, if certain
financial results are achieved. The Company's contributions to the 401(k) Plan
were $.2 million in 1998 and $.3 million in 1997 and 1996.
11. Quarterly financial data (unaudited)
The following is a tabulation of unaudited quarterly operating results for
1998 and 1997 (in thousands, except for per share data):
Basic Diluted
Operating Gross Net Net Income Net Income
Revenues Profit Income (loss) Per Share Per Share
First Quarter $ 11,473 $ 4,569 $ 2,071 $ .09 $ .09
Second Quarter 9,590 3,136 1,514 .07 .07
Third Quarter 10,105 2,926 1,378 .06 .06
Fourth Quarter 8,642 1,665 (1,084) (.04) (.04)
------- ------- ------- ----- -----
$ 39,810 $ 12,296 $ 3,879 $ .18 $ .18
======= ======= ======= ===== =====
1997
First Quarter $ 17,025 $ 8,952 $ 4,816 $ .22 $ .22
Second Quarter 15,988 8,787 4,652 .21 .21
Third Quarter 16,775 8,697 5,136 .23 .23
Fourth Quarter 17,327 8,533 4,656 .22 .21
------- ------- ------- ----- -----
$ 67,115 $ 34,969 $ 19,260 $ .88 $ .87
======= ======= ======= ===== =====
12. Subsequent Event
On December 23, 1998, the Company announced that it had entered into an
agreement with Aera Energy, LLC to acquire the Placerita, California oilfield
for $35 million in cash. The Company closed the transaction on February 12,
1999. The Placerita oilfield consists of six leases and two fee properties
totaling approximately 700 acres and produces approximately 2,800 net BPD
of 13 degree gravity crude oil. The Company estimates the property has
approximately 20 million barrels of proved reserves, of which 65% are
developed. The acquisition also includes a 42 megawatt cogeneration facility
which generates electricity sold to a major utility and provides approximately
13,500 BSPD for injection into the reservoir. The Company financed the
acquisition through borrowings under its credit facility.
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36
BERRY PETROLEUM COMPANY
Supplemental Information About Oil & Gas Producing Activities (Unaudited)
The following estimates of proved oil and gas reserves, both developed and
undeveloped, represent interests owned by the Company located solely within the
United States. Proved reserves represent estimated quantities of crude oil
and natural gas which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved developed oil and gas
reserves are the quantities expected to be recovered through existing wells
with existing equipment and operating methods. Proved undeveloped oil and gas
reserves are reserves that are expected to be recovered from new wells on
undrilled acreage, or from existing wells for which relatively major
expenditures are required for completion.
Disclosures of oil and gas reserves which follow are based on estimates
prepared by independent engineering consultants as of December 31, 1998, 1997
and 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. The information
provided does not represent Management's estimate of the Company's expected
future cash flows or value of proved oil and gas reserves.
Changes in estimated reserve quantities
The net interest in estimated quantities of proved developed and
undeveloped reserves of crude oil and natural gas at December 31, 1998, 1997
and 1996, and changes in such quantities during each of the years then ended
were as follows (in thousands):
1998 1997 1996
Oil Gas Oil Gas Oil Gas
Mbbls Mmcf Mbbls Mmcf Mbbls Mmcf
Proved developed and
undeveloped reserves:
Beginning of year 100,454 3,531 101,336 4,682 77,071 5,983
Revision of
previous
estimates (4,894) 774 3,647 (869) 739 (810)
Production (4,359) (245) (4,503) (282) (3,491) (491)
Sale of reserves
in place - - (26) - - -
Purchase of reserves
in place 732 - - - 27,017 -
------- ------ ------- ------ ------- ------
End of year 91,933 4,060 100,454 3,531 101,336 4,682
======= ====== ======= ====== ======= ======
Proved developed
reserves:
Beginning of year 86,858 1,457 76,358 2,608 62,856 3,380
======= ====== ======= ====== ======= ======
End of year 83,532 1,604 86,858 1,457 76,358 2,608
======= ====== ======= ====== ======= ======
36
37
BERRY PETROLEUM COMPANY
Supplemental Information About Oil & Gas Producing Activities
(Unaudited)(Cont'd)
The standardized measure has been prepared assuming year end sales prices
adjusted for fixed and determinable contractual price changes, current costs
and statutory tax rates (adjusted for tax credits and other items), and a ten
percent annual discount rate. No deduction has been made for depletion,
depreciation or any indirect costs such as general corporate overhead or
interest expense.
Standardized measure of discounted future net cash flows from estimated
production of proved oil and gas reserves (in thousands):
1998 1997 1996
Future cash inflows $ 656,607 $ 1,232,749 $ 1,875,373
Future production and development
Costs (388,546) (421,305) (429,879)
Future income tax expenses (33,577) (246,668) (495,412)
-------- -------- --------
Future net cash flows 234,484 564,776 950,082
10% annual discount for
estimated timing of cash flows (127,967) (297,182) (529,523)
-------- -------- --------
Standardized measure of discounted
future net cash flows $ 106,517 $ 267,594 $ 420,559
======== ======== ========
Pre-tax standardized measure of
discounted future net cash flows $ 113,811 $ 376,459 $ 634,579
======== ======== ========
Average sales prices at December 31:
Oil ($/bbl) $ 7.05 $ 12.19 $ 18.37
Gas ($/mcf) $ 2.10 $ 2.33 $ 3.02
Changes in standardized measure of discounted future net cash flows from proved
oil and gas reserves (in thousands):
1998 1997 1996
Standardized measure -
beginning of year $ 267,594 $ 420,559 $ 208,301
-------- -------- --------
Sales of oil and gas produced,
net of production costs (22,030) (44,765) (37,677)
Revisions to estimates of proved
reserves:
Net changes in sales prices and
production costs (216,265) (259,026) 170,529
Revisions of previous quantity
Estimates (8,400) 14,014 4,020
Change in estimated future
development costs (17,262) (1,775) (19,294)
Purchases of reserves in place 1,597 - 171,456
Sale of reserves in place - (244) -
Development costs incurred during
the period 6,728 18,597 9,305
Accretion of discount 37,539 63,458 30,837
Income taxes 46,293 109,780 (101,936)
Other 10,723 (53,004) (14,982)
-------- -------- --------
Net increase (decrease) (161,077) (152,965) 212,258
-------- -------- --------
Standardized measure - end of year $ 106,517 $ 267,594 $ 420,559
======== ======== ========
37
38
BERRY PETROLEUM COMPANY
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
The information called for by Item 10 is incorporated by reference from
information under the caption "Election of Directors" in the Company's
definitive proxy statement to be filed pursuant to Regulation 14A no later than
120 days after the close of its fiscal year. The information on Executive
Officers is contained in Part I of this Form 10-K.
Item 11. Executive Compensation
The information called for by Item 11 is incorporated by reference from
information under the caption "Executive Compensation" in the Company's
definitive proxy statement to be filed pursuant to Regulation 14A no later than
120 days after the close of its fiscal year.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information called for by Item 12 is incorporated by reference from
information under the captions "Ownership by Directors and Management" and
"Principal Shareholders" in the Company's definitive proxy statement to be
filed pursuant to Regulation 14A no later than 120 days after the close of
its fiscal year.
Compliance with Section 16(a) of the Securities Exchange Act of 1934
Section 16(a) of the Securities Exchange Act of 1934 and related
Securities and Exchange Commission rules require that Directors and
Executive Officers report to the Securities and Exchange Commission changes
in their beneficial ownership of Berry stock, and that any late filings be
disclosed. Based solely on a review of the copies of such forms furnished
to the Company, or written representations that no Form 5 was required, the
Company believes that all Section 16(a) filing requirements were complied with.
Item 13. Certain Relationships and Related Transactions
The information called for by Item 13 is incorporated by reference from
information under the caption "Certain Relationships and Related Transactions"
in the Company's definitive proxy statement to be filed pursuant to Regulation
14A no later than 120 days after the close of its fiscal year.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
A. Financial Statements and Schedules
See Index to Financial Statements and Supplementary Data in Item 8.
B. Reports on Form 8-K
A Form 8-K was filed on February 26, 1999 to report an Item 2 -
Acquisition of Assets. The Form 8-K was filed to report the acquisition
on February 12, 1999 of the Placerita oilfield assets for $35 million.
38
39
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 10.1 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1997, File No.
1-9735)
10.2* Salary Continuation Agreement dated as of December 5, 1997,
by and between Registrant and Jerry V. Hoffman (filed as Exhibit
10.2 to the Registrant's Annual Report on Form 10-K for the year
ended December 31, 1997, File No.1-9735)
10.3* Form of Salary Continuation Agreement dated as of December 5,
1997, by and between Registrant and Ralph J. Goehring and
Michael R. Starzer (filed as Exhibit 10.3 to the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1997, File No. 1-9735)
10.4* Form of Salary Continuation Agreements dated as of March 20,
1987, as amended August 28, 1987, by and between Registrant
and selected employees of the Company (filed as Exhibit 10.12
to the Registration Statement on Form S-1 filed on June 7,
1989, File No. 33-29165)
10.5* Instrument for Settlement of Claims and Mutual Release by
and among Registrant, Victory Oil Company, the Crail Fund
and Victory Holding Company effective October 31, 1986
(filed as Exhibit 10.13 to Amendment No. 1 to the
Registrant's Registration Statement on Form S-4 filed
on May 22, 1987, File No. 33-13240)
10.6* Warrant Certificate dated November 14, 1996, by and
between Registrant and Tannehill Oil Company (filed as
Exhibit 10.16 in Registrant's Form 10-K filed on March 21,
1997, File No. 1-9735)
10.7* 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)
10.8* Standard Offer #2 Power Purchase Agreement dated May 1984
by and between Registrant's predecessor and Pacific Gas
and Electric Company (filed as Exhibit 10.14 in Registrant's
Form 10-K filed on March 21, 1997, File No. 1-9735)
10.9* Standard Offer #1 Power Purchase Agreement dated
January 16, 1997, by and between Registrant and Pacific
Gas and Electric Company (filed as Exhibit 10.15 in
Registrant's Form 10-K filed on March 21, 1997,
File No. 1-9735) 10.10* Purchase and Sale Agreement,
dated as of January 26, 1999, by and between the Registrant
and Aera Energy LLC (filed as Exhibit 10.1 to the
Registrant's Form 8-K filed on February 26, 1999,
File No. 1-9735)
10.11* Standard Offer #2 Power Purchase Agreement
(Newhall Phase I), as amended, dated December 1985,
between Tenneco Oil Company and Southern California Edison
(filed as Exhibit 10.2 to the Registrant's Form 8-K filed
on February 26, 1999, File No. 1-9735)
10.12* Standard Offer #2 Power Purchase Agreement
(Newhall Phase II), as amended, dated December 1985,
between Tenneco Oil Company and Southern California
Edison (filed as Exhibit 10.3 to the Registrant's
Form 8-K filed on February 26, 1999, (File No. 1-9735)
39
40
Exhibits (cont'd)
Exhibit No. Description of Exhibit Page
10.13 Amended and Restated 1994 Stock Option Plan 42
10.14 Second Amendment to Credit Agreement dated as of
January 21, 1999, by and between Registrant and
NationsBank, N.A. 49
23.1 Consent of PricewaterhouseCoopers LLP 76
23.2 Consent of DeGolyer and MacNaughton 77
27. ** Financial Data Schedule
99.1 Undertaking for Form S-8 Registration Statements 79
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
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 12, 1999.
BERRY PETROLEUM COMPANY
/s/ JERRY V. HOFFMAN /s/ RALPH J. GOEHRING /s/ DONALD A. DALE
JERRY V. HOFFMAN RALPH J. GOEHRING DONALD A. DALE
Chairman of the Board, Senior Vice President and Controller
President and Chief Chief Financial Officer Principal Accounting Officer)
Executive Officer (Principal Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities on the dates so indicated.
Name Office Date
/s/ Jerry V. Hoffman Chairman of the Board, President March 12, 1999
Jerry V. Hoffman & Chief Executive Officer
/s/ William F. Berry Director March 12, 1999
William F. Berry
/s/ Gerry A. Biller Director March 12, 1999
Gerry A. Biller
/s/ Ralph B. Busch, III Director March 12, 1999
Ralph B. Busch, III
/s/ William E. Bush, Jr. Director March 12, 1999
William E. Bush, Jr.
/s/ Richard F. Downs Director March 12, 1999
Richard F. Downs
/s/ John A. Hagg Director March 12, 1999
John A. Hagg
/s/ Thomas J. Jamieson Director March 12, 1999
Thomas J. Jamieson
/s/ Roger G. Martin Director March 12, 1999
Roger G. Martin
40