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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, 1999
Commission file number 1-9735
BERRY PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 77-0079387
(State of incorporation or organization) (I.R.S. Employer Identification Number)
28700 Hovey Hills Road
Taft, California 93268
(Address of principal executive offices, including zip code)
Registrant's telephone number, including area code: (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 16, 2000, the registrant had 21,113,383 shares of Class A
Common Stock outstanding and the aggregate market value of the voting stock
held by nonaffiliates was approximately $234,039,000. This calculation is
based on the closing price of the shares on the New York Stock Exchange on
February 16, 2000 of $16.1875. The registrant also had 898,892 shares of
Class B Stock outstanding on February 16, 2000, 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.
1
BERRY PETROLEUM COMPANY
TABLE OF CONTENTS
PART I
Items 1
and 2. Business and Propertie ................................ 3
General ......................................... 3
Oil Marketing ................................... 4
Steaming Operations ............................. 5
Electricity Generation .......................... 6
Environmental and Other Regulations ............. 7
Competition ..................................... 7
Employees ....................................... 7
Oil and Gas Properties .......................... 8
Development .................................. 8
Exploration .................................. 9
Enhanced Oil Recovery Tax Credits ............... 10
Oil and Gas Reserves ............................ 10
Production ...................................... 10
Acreage and Wells ............................... 11
Drilling Activity ............................... 11
Title and Insurance ............................. 11
Item 3. Legal Proceedings .................................. 12
Item 4. Submission of Matters to a Vote of
Security Holders ................................. 13
Executive Officers ................................. 13
PART II
Item 5. Market for the Registrant's Common Equity and
Related Shareholder Matters ...................... 14
Item 6. Selected Financial Data ............................ 15
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations .............. 16
Item 8. Financial Statements and Supplementary Data ........ 20
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure ........... 39
PART III
Item 10. Directors and Executive Officers of the Registrant . 39
Item 11. Executive Compensation ............................. 39
Item 12. Security Ownership of Certain Beneficial
Owners and Management .............................. 39
Item 13. Certain Relationships and Related Transactions ..... 39
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K .............................. 39
2
PART I
Items 1 and 2. Business and Properties
General
Berry Petroleum Company, ("Berry" or "Company"), is an independent energy
company engaged in the production, development, acquisition, exploitation and
exploration of crude oil and natural gas. While the Company was incorporated
in Delaware in 1985 and has been a publicly traded company since 1987, it can
trace its roots in California oil production back to 1909. Currently, Berry's
principal reserves and producing properties are located in Kern, Los Angeles
and Ventura Counties in California. Information contained in this report on
Form 10-K reflects the business of the Company during the year ended
December 31, 1999. 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. In conjunction with the goals of being a low-cost heavy oil producer
and the exploitation and development of its large heavy crude oil base, the
Company owns three cogeneration facilities which provide an efficient and
secure long-term supply of steam which is necessary for the economic
production of heavy oil. Berry views these assets as a critical part of its
long-term success. Berry believes that its primary strengths are its ability
to maintain a low-cost operation, its flexibility in acquiring attractive
producing properties which have significant exploitation and enhancement
potential and its experienced management team. While the Company continues
to be an active acquirer in California, it is investigating several other
basins which would establish another core area and provide for additional
growth opportunities and diversification of the Company's predominantly
heavy oil resource base. The Company has unused borrowing capacity
to finance acquisitions and will consider, if appropriate, the issuance of
capital stock to finance future purchases.
Proved Reserves
As of December 31, 1999, the Company's estimated proved reserves were
112.5 million barrels of oil equivalent, (BOE), of which 99.5% is heavy crude
oil, i.e., oil with an API gravity of less than 20 degrees. A significant
portion of these proved reserves is owned in fee. Substantially all of the
Company's reserves as of December 31, 1999 were located in California with
76%, 18% and 5% of total proved reserves in Kern, Los Angeles and Ventura
Counties, respectively. The Company's reserves have a long life, in excess
of 20 years, which is primarily a result of the Company's strong position in
heavy crude oil (the Company's properties in the Midway-Sunset and the
Placerita fields average 13 degree API gravity and the Montalvo field averages
16 degree API gravity). Production in 1999 was 5.1 million BOE, up 16% from
1998 production of 4.4 million BOE. For the five years 1995 through 1999, the
Company's average annual reserve replacement rate was 245% and the finding
and development cost was $2.67 per BOE.
Acquisitions
In February 1999, the Company completed the acquisition of the Placerita
oilfield, located in northern Los Angeles County for approximately $35 million.
This acquisition was financed utilizing the Company's revolving credit
facility. These properties currently produce approximately 3,200 net barrels
of heavy oil per day. The proved reserves associated with the Placerita
properties are approximately 20 million barrels. Included in the purchase
price was a 42 megawatt dual-turbine cogeneration facility which provides
steam for the thermally enhanced oil recovery methods used on the properties.
3
Operations
Berry operates all of its principal oil producing properties. The Midway-
Sunset and Placerita fields contain predominantly heavy crude oil which
requires heat, supplied in the form of steam, injected into the oil producing
formations to reduce the oil viscosity which improves the mobility of the oil
flowing to the well-bore for production. Berry utilizes cyclic steam recovery
methods in the Midway-Sunset field, steam-drive in the Placerita field and
primary recovery methods at its Montalvo field. Berry is able to produce its
heavy oil at its Montalvo field without the necessity of steam since the
producing reservoir is at a depth in excess of 12,000 feet and thus the
reservoir temperature is high enough to produce the oil without the assistance
of additional heat from steam. Field operations include the initial recovery
of the crude oil and its transport through treating facilities into storage
tanks. After the treating process is completed, which includes removal of
water and solids by mechanical, thermal and chemical processes, the crude oil
is metered through Lease Automatic Custody Transfer (LACT) units and either
transferred into crude oil pipelines owned by other companies or, in the case
of the Placerita field, transported via trucks. The point-of-sale is usually
the LACT unit or truck loading facility.
Revenues
The percentage of revenues by source for the prior three years is as
follows:
1999 1998 1997
Sales of oil and gas 99% 100% 97%
Interest and other income 1% -% (1) 3%
(1) less than 1%
Oil Marketing
The world and California markets for crude oil remained extremely depressed
throughout 1998 and into early 1999. In late February 1999, OPEC and certain
non-OPEC countries agreed to significantly reduce oil production with the goal
of eliminating the worldwide oil glut and thus increase oil prices. This
cohesive pact was highly successful, laying the foundation for a significant
improvement in oil prices. The price for West Texas Intermediate (WTI), the
U.S. benchmark crude oil, rose from $11.37/bbl to $27.07/bbl during 1999.
Supply was also curtailed as a result of a significant reduction in capital
spending in the sector. The worldwide demand for oil increased throughout
1999 as many of the world economies strengthened. As we enter 2000, it
appears that most economies are doing well and that growth will continue
with some economists predicting demand to be over 78 million barrels of oil
per day by the end of 2000 versus under 75 million barrels per day demand in
late 1998.
The crude price differential between WTI and California's heavy crude oil
continues to be volatile, but has averaged $5.97, $5.97 and $5.74 for 1999,
1998 and 1997, respectively. The Company believes the differential will
continue near these levels in 2000.
The Pacific Pipeline was completed in 1999 and is able to deliver
unblended San Joaquin Valley heavy crude oil into the Los Angeles refining
market. This pipeline is insulated and provides another transportation
outlet for San Joaquin Valley heavy crude oil without requiring lighter
crude oil volumes as transportation blendstock. While the Company believes
this development is positive, it is very difficult to determine if this
additional outlet has favorably impacted the prices received for the
Company's crude oil.
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 on 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
4
premiums, the level of which depends upon current market conditions. One of
the Company's properties, with production of approximately 3,200 barrels
per day (B/D), is burdened by a price-sensitive royalty. The royalty is
75% of the heavy oil posted price above a specified level, escalated and
calculated annually. 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 two
bracketed zero cost collar hedge contracts with two refiners as part of its
price protection program. This price protection program is designed to
moderate the effects of severe price downturns while allowing Berry to
participate in 100% of the upside after a $3/bbl payment on 6,500 B/D.
Of this 6,500 B/D, Berry participates on 5,000 B/D above $15.50/bbl and
on 1,500 B/D above $17.50/bbl. These price triggers are based on
heavy oil postings and both contracts expire at year-end 2000.
At the present time, Management believes it is adequately hedged in the
event of another severe oil price decline. These price protection activities
resulted in a net cost to the Company of $.51 per barrel in 1999 and
contributed $.50 to the average price received for the Company's crude oil
in 1998. Berry's 1999 average heavy crude oil sales price was $13.08 per
barrel, up $4.06 per barrel, or 45% from $9.02 in 1998.
Steaming Operations
At December 31, 1999, approximately 95% of the Company's proved reserves,
or 107 million barrels, consisted of heavy crude oil produced from depths
averaging less than 2,000 feet. The Company, in achieving its goal of being
a low cost heavy oil producer, has focused on reducing its steam cost by the
purchase of its 38 megawatt cogeneration facility in 1995 and another
18 megawatt cogeneration facility in 1996 which was part of the purchase of
additional oil properties in the South Midway-Sunset Field. In early 1999,
the Company purchased the Placerita oilfield which is highly dependent on
low-cost steam for economic production. This purchase also included a
42 megawatt cogeneration facility. Steam generation from these facilities
is more efficient than conventional steam generators, as both steam and
electricity are produced from the same natural gas fuel supply. In addition,
the Company's ownership of these facilities allows for absolute control over
the steam supply which is crucial for the maximization of oil production and
ultimate reserve recovery.
The Company has adequate productive steam capacity for its requirements at
all three core areas. 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.
Midway-Sunset Field
For its South Midway-Sunset properties, the Company's current steam
production is generated by its 38 and 18 megawatt cogeneration facilities
(approximately 18,500 barrels of steam per day (BSPD)) and, as needed, from
conventional steam generators. In addition, the Company uses 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.
The Company also has a steam contract from an on-site, non-owned cogeneration
facility for a minimum delivery of 2,000 BSPD for use in the Company's
operations. Conventional steam generators are used by the Company as required
to maintain current production levels, to economically produce additional
crude oil and as emergency back-up steam generation to the cogeneration
facilities. In early 1998, the Company temporarily shut down the duct-firing
steam capacity at its 38 megawatt facility and reduced the utilization of
conventional steam generators to reduce costs and improve cash flow. The
Company began increasing the volume of steam injected in this field in late
1998 and early 1999 through duct-firing and conventional steam generation.
On its North Midway-Sunset properties, the Company relies solely on
conventional steam generators for its steam requirements.
The Company's two cogeneration facilities in the South Midway-Sunset field
sell electricity to a large California-based utility under separate contracts.
The 38 megawatt facility has a 15-year Standard Offer #1 (SO1) contract, which
results in a long-term buyer for the electricity and expires in 2012. The 18
megawatt facility has a Standard Offer #2 (SO2) contract which expires in
January, 2002.
5
Placerita
On its Placerita properties, the Company generates approximately
13,500 BSPD from its 42 megawatt cogeneration facility, buys another
5,000 BSPD from a third party cogeneration facility when available, and
generates another 6,000 BSPD from conventional steam generators.
The 42 megawatt facility, 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 Midway-Sunset contracts.
The Company has physical access to gas pipelines, such as the Kern River/
El Paso and Southern California Gas Company systems, to transport its gas
purchases required for steam generation. The Company has no long-term gas
delivery contracts and none of the Company's cogeneration facilities are
subject to any long-term gas transportation agreements. The Company believes
there is sufficient capacity to deliver natural gas to the Company's
properties.
Electricity Generation
The Company's three cogeneration facilities, when combined, have
electricity production capacity of 98 megawatts of electricity per hour.
Each facility is located on a centrally-located oil property such that the
steam generated by the facility is capable of being delivered to the oil
properties that require the steam for production purposes. The Company is
now in an enviable position because it has succeeded in acquiring a secure
long-term source of low-cost steam, and in many cases, the steam volumes and
low cost is the determining factor as to the economic viability of a
thermally enhanced heavy oil project. The proceeds received from the sale of
electricity offset a large portion of the cost of producing steam and are
reported as a reduction of operating costs in the Company's financial
statements. While these electricity revenues are substantial, the Company's
investments in these facilities have been for the express purpose of lowering
the steam cost in its heavy oil operations and securing operating control of
the respective steam generation. The Company views the generation of
electricity as a by-product and while it must compete in the electrical
generation marketplace, it does not consider itself, nor does it
intend to position itself, as a competitor in the electrical industry.
One of Berry's challenges in the next few years will be to maximize the
cashflow from the operations of these facilities as the California electrical
market continues on its path of full deregulation and as the Company's SO2
contracts, which represent a premium in current electrical revenue over current
market prices, expire. In the current environment prior to deregulation, the
electrical revenue is linked to the price of natural gas at the California
border. Upon full deregulation, now believed to occur in 2001, electricity
prices will have a reduced correlation to natural gas prices, and will be more
heavily influenced by other sources of electrical generation, e.g.,
hydroelectric power, nuclear power, coal and other sources. In addition,
the electrical demand is expected to cause greater volatility in the
electrical prices received by the Company. Changes in the electrical prices
for California power will directly impact the Company's steam costs and,
therefore, its operating costs. Due to this massive change in California's
electrical industry, the Company's primary goal is to maximize its existing
electrical generation capacity, while minimizing the volatility in the
Company's steam cost. Management believes that this will be possible in the
long-term, but in the transition period it may be more difficult.
6
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 if the Company
fails 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.
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 oil and gas 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,
1999 which would have a material impact upon the Company's financial position
or results of operations.
Competition
The oil and gas industry is highly competitive. As an independent
producer, the Company does not own any refining or retail outlets and,
therefore, it has little control over the price it receives for its crude
oil. As such, higher costs, fees and taxes assessed at the producer level
cannot necessarily be passed on to the Company's customers. In acquisition
activities, significant competition exists 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 Berry is in a position to compete effectively due to its low cost
structure, transaction flexibility, strong financial position, experience
and determination.
Employees
On December 31, 1999, the Company had 108 full-time employees, up from 88
employees at year-end 1998. This increase in employees from 1998 is primarily
due to the acquisition of the Placerita properties.
7
Oil and Gas Properties
Development
South Midway-Sunset - Berry owns and operates working interests in 22
properties consisting of 2,010 acres located in the South Midway-Sunset field.
The Company estimates these properties account for approximately 69% of the
Company's proved oil and gas reserves and approximately 69% of its current
daily production. Of these properties, 14 are owned in fee. The wells
produce from an average depth of approximately 1,200 feet, and rely on
thermal EOR methods, primarily cyclic steaming.
During 1999, the primary focus in this field was directed at the continued
development of the Formax properties, acquired in 1996 and the continued
application of horizontal well technology in the Monarch sands. Of the 20
wells drilled in this area in 1999, 14 were drilled on the Formax properties,
and 11 were horizontal 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 2000, the Company plans to drill an additional
46 development wells in this field, 12 of which will be horizontal and perform
an extensive 3-D seismic survey on a portion of the properties purchased in
the last few years.
North Midway-Sunset - Berry owns and operates approximately 1,975 acres in
the North Midway-Sunset field which account for approximately 8% of the
Company's proved oil and gas reserves and 5% 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 1,200 feet.
During 1999, the Company drilled one exploitation well to further evaluate
the diatomite accumulation on top of the Fairfield anticline. In 2000, the
Company plans to drill a horizontal diatomite test well, an exploitation well
to test Plio-Pleistocene oil sands present in the southwest syncline area,
and a horizontal well in the Potter formation.
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 5% of
Berry's proved oil and gas reserves and approximately 5% of Berry's daily
production. The wells produce from an average depth of approximately 12,500
feet. No new wells were drilled in 1999 or are budgeted in 2000, however,
several remedials are planned in 2000.
Placerita - On February 12, 1999, Berry acquired the Placerita oilfield,
which established a new core area, 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 Company estimates current
proved reserves from Placerita account for approximately 18% of Berry's
proved oil and gas reserves and approximately 21% of Berry's daily production.
The average depth of the wells is approximately 1,800 feet. These properties
rely on thermal methods, primarily steam drive.
One water disposal well was drilled in 1999. In 2000, the Company plans
to drill two core holes, six development wells, and two horizontal producers,
as well as expand the steamflood.
8
The following is a summary of capital expenditures incurred during 1999
and 1998 and projected capital expenditures for 2000:
CAPITAL EXPENDITURES SUMMARY
(in thousands)
2000(1) 1999 1998
(Projected)
South Midway-Sunset Field
New wells $ 5,670 $ 3,120 $ 2,886
Remedials/workovers 750 607 767
Facilities 590 337 1,028
Cogeneration facilities 320 3,126 623
------- ------- -------
7,330 7,190 5,304
------- ------- -------
Placerita
New wells 2,400 310 -
Remedials/workovers 950 69 -
Facilities 1,570 784 -
Cogeneration facilities 780 - -
------- ------- -------
5,700 1,163 -
------- ------- -------
North Midway-Sunset Field
New wells 893 150 826
Remedials/workovers - 25 57
Facilities - 18 45
------- ------- -------
893 193 928
------- ------- -------
Montalvo
Remedials/workovers 615 16 117
Facilities 650 37 108
------- ------- -------
1,265 53 225
------- ------- -------
Other 628 523 524
------- ------- -------
Totals $ 15,816 $ 9,122 $ 6,981
======= ======= =======
(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.
Exploration
The Company did not participate in the drilling of any exploratory wells
in 1999 or 1998 and has none budgeted for 2000. In recent years, the Company
has concentrated on growth through development of existing assets and
strategic acquisitions. The Company is pursuing an acquisition strategy
which may include some exploration drilling in the future.
9
Enhanced Oil Recovery Tax Credits
The Revenue Reconciliation Act of 1990 included a tax credit for certain
costs associated with extracting high-cost, capital-intensive marginal oil or
gas and which utilizes at least one of nine designated "enhanced" or tertiary
recovery methods. Cyclic steam and steam drive recovery methods for heavy oil,
which Berry utilizes extensively, are qualifying EOR methods. In 1996,
California conformed to the federal law, thus, on a combined basis, the Company
is able to achieve credits approximating 12% of its qualifying costs. The
credit is earned for only qualified EOR projects by investing in one of three
types of expenditures: 1) drilling development wells, 2) adding facilities
that are integrally related to qualified EOR production, or 3) utilizing a
tertiary injectant, such as steam, to produce oil. The credit may be utilized
to reduce the Company's tax liability down to, but not below, its alternative
minimum tax liability. This credit is significant in reducing the Company's
income tax liabilities and effective tax rate.
Oil and Gas Reserves
The Company continued to engage DeGolyer and MacNaughton (D&M) to estimate
the proved oil and gas reserves and the future net revenues to be derived from
properties of the Company for the year ended December 31, 1999. D&M is an
independent oil and gas consulting firm located in Dallas, Texas. In preparing
their reports, D&M reviewed and examined geologic, economic, engineering and
other data considered applicable to properly determine the reserves of the
Company. They also examined the reasonableness of certain economic assumptions
regarding forecasted operating and development costs and recovery rates in
light of the economic environment on December 31, 1999. 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:
1999 1998 1997
Net annual production:(1)
Oil (Mbbls) 5,060 4,359 4,503
Gas (Mmcf) 180 245 282
Total equivalent barrels(2) 5,090 4,399 4,550
Average sales price:
Oil (per bbl) $ 13.08 $ 9.02 $ 14.70
Gas (per mcf) 1.90 2.64 2.68
Per BOE 13.07 9.05 14.71
Average production cost (per BOE) 4.33 4.05 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. A barrel of
oil (bbl) is equivalent to 42 U.S. gallons.
10
Acreage and Wells
At December 31, 1999, the Company's properties accounted for the following
developed and undeveloped acres:
Developed Acres Undeveloped Acres
Gross Net Gross Net
------ ------ ------ ------
California 7,166 7,165 7,244 7,244
Other 360 41 - -
------ ------ ------ ------
7,526 7,206 7,244 7,244
====== ====== ====== ======
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 2,390 gross oil wells (2,386 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:
1999 1998 1997
Gross Net Gross Net Gross Net
Exploratory wells drilled:
Productive - - - - - -
Dry(1) - - - - - -
Development wells drilled:
Productive 21 21 20 20 89 89
Dry(1) - - 1 1 1 1
Total wells drilled:
Productive 21 21 20 20 89 89
Dry(1) - - 1 1 1 1
(1) A dry well is a well found to be incapable of producing either oil or
gas in sufficient quantities to justify completion as an oil or gas well
Title and Insurance
To the best of the Company's knowledge, there are no defects in the title
to any of its principal properties including related facilities.
Notwithstanding the absence of a recent title opinion or title insurance
policy on all of its properties, the Company believes it has satisfactory
title to its properties, subject to such exceptions as the Company believes
are customary and usual in the oil and gas industry and which the Company
believes will not materially impair its ability to recover the proved oil
and gas reserves or to obtain the resulting economic benefits.
The oil and gas business can be hazardous, involving unforeseen
circumstances such as blowouts or environmental damage. Although it is not
insured against all risks, the Company maintains a comprehensive insurance
program to address the hazards inherent in the oil and gas business.
11
Item 3. Legal Proceedings
The Company is a cross-defendant in litigation pending in the Los Angeles
County Superior Court. The original lawsuit was filed in June 1996, and the
Company was served as a Doe cross-defendant in June 1997. The complaint
involves an oil and gas lease located in Los Angeles County and seeks to
recover approximately $.6 million in clean up costs allegedly incurred by the
plaintiff/lessor after the lease that dated back to the late 1940's was
terminated by the then lessee. Substantially all of the lessees in the chain
of title from the late 1940's to the date of termination were named as
defendants. The cross-complaint by Placerita Oil Company, Inc. ("POCI"),
the last of the lessees, seeks indemnification from the other lessees in the
chain of title as to the plaintiff's claims. Although the Company was never
a lessee in the chain of title, Berry acquired all of the stock of one of the
lessees (TEORCO) that had been in the chain of title in prior years. TEORCO
assigned the leases to POCI approximately two years prior to Berry's acquiring
the stock of TEORCO. POCI's cross-complaint also seeks an unknown amount, but
which could be as much as $49 million in damages from TOSCO Corporation and
from TEORCO, the entity that in 1986 assigned to POCI the lease and two other
leases, on the basis of alleged fraud by TOSCO, et al. in overstating the oil
and gas reserves to POCI. TOSCO is the same entity that sold the stock of
its subsidiary, TEORCO, to Berry in 1988. Berry has potential successor
liability because of its acquisition of the stock of TEORCO. In the third
and fourth quarter of 1999, the scope of the litigation broadened
substantially and required increasing resources to defend. The Company
is vigorously defending itself and has incurred significant legal expenses
that impact general and administrative expenses. The case is currently being
tried before a jury with a likely initial outcome in the first quarter of
2000. Although Management believes it has a strong defense in the lawsuit,
the ultimate outcome cannot be determined at this time. Therefore, no
receivable or liability has been recorded by the Company.
While the Company, is from time to time, a party to certain lawsuits in
the ordinary course of business, the Company is not a party to any other
lawsuits not mentioned herein as of February 16, 2000.
12
Item 4. Submission of Matters to a Vote of Security Holders
None.
Executive Officers
Listed below are the names, ages (as of December 31, 1999) 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, 50, 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.
RALPH J. GOEHRING, 43, Senior Vice President and Chief Financial Officer.
Mr. Goehring has been Senior Vice President since April 1997, Chief Financial
Officer since March 1992 and was Manager of Taxation from September 1987 until
March 1992. Mr. Goehring is also an Assistant Secretary for the Company.
MICHAEL R. STARZER, 38, has been Vice President of Corporate Development
since March 1996 and was Manager of Corporate Development from April 1995 to
March 1996. 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.
BRIAN L. REHKOPF, 52, has been Manager of Engineering since September 1997.
Mr. Rehkopf, a registered petroleum engineer, joined the Company's engineering
department in June 1997 and was previously a Vice President and Asset Manager
with ARCO Western Energy, a subsidiary of Atlantic Richfield Corp. (ARCO) since
1992 and an Operations Engineering Supervisor with ARCO from 1988 to 1992. Mr.
Rehkopf is also an Assistant Secretary for the Company.
GEORGE T. CRAWFORD, 39, has been Manager of Production, since January 1,
1999. Mr. Crawford, a petroleum engineer, was previously the Production
Engineering Supervisor for ARCO Western Energy. Mr. Crawford was employed by
ARCO from 1989 to 1998 in numerous engineering and operational assignments
including Production Engineering Supervisor, Planning and Evaluation Consultant
and Operations Superintendent.
DONALD A. DALE, 53, has been Controller since December 1985. Mr. Dale was
the Controller for the Company's predecessor from September 1985 to December
1985.
KENNETH A. OLSON, 44, has been 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.
13
PART II
Item 5. Market for the Registrant's Common Equity and Related Shareholder
Matters
Shares of Class A Common Stock (Common Stock) and Class B Stock, referred
to collectively as the "Capital Stock," are each entitled to one vote and 95%
of one vote, respectively. Each share of Class B Stock is entitled to a
$1.00 per share preference in the event of liquidation or dissolution.
Further, each share of Class B Stock is convertible into one share of Common
Stock at the option of the holder.
In November 1999, the Company adopted a Shareholder Rights Agreement and
declared a dividend distribution of one such Right for each outstanding share
of Capital Stock on December 8, 1999. Each share of Capital Stock issued after
December 8, 1999 includes one Right. The Rights expire on December 8, 2009.
See Note 7 of Notes to the Financial Statements.
In conjunction with the acquisition of the Tannehill assets in 1996, the
Company issued a Warrant Certificate to the beneficial owners of Tannehill Oil
Company. This Warrant authorizes the purchase of 100,000 shares of Berry
Petroleum Company Class A Common Stock until November 8, 2003 at $14.06 per
share. All the warrants are currently outstanding and the underlying shares
will not be registered under the Securities Act of 1933.
Berry's Class A Common Stock is listed on the New York Stock Exchange
under the symbol "BRY". The Class B Stock is not publicly traded. The market
data and dividends for 1999 and 1998 are shown below:
1999 1998
Price Range Dividends Price Range Dividends
High Low per Share High Low per Share
First Quarter $ 14 1/8 $ 8 11/16 $ .10 $ 17 1/2 $ 13 3/4 $ .10
Second Quarter 14 5/8 11 1/8 .10 15 3/8 13 .10
Third Quarter 14 11/16 13 1/8 .10 13 13/16 10 1/2 .10
Fourth Quarter 15 7/16 12 1/4 .10 14 1/4 11 1/2 .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 16,
2000, December 31, 1999 and December 31, 1998 was $16 3/16, $15 1/8 and
$14 3/16, respectively.
The number of holders of record of the Company's Common Stock was 809 (and
approximately 3,600 street name shareholders) as of February 16, 2000. There
was one Class B Stockholder of record as of February 16, 2000.
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
41 consecutive quarters through December 31, 1999. 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, 1999, 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.
14
Item 6. Selected Financial Data
The following table sets forth certain financial information with respect
to the Company and is qualified in its entirety by reference to the historical
financial statements and notes thereto of the Company included in Item 8,
"Financial Statements and Supplementary Data." The statement of operations and
balance sheet data included in this table for each of the five years in the
period ended December 31, 1999 were derived from the audited financial
statements and the accompanying notes to those financial statements
(in thousands, except per share and per barrel data):
1999 1998 1997 1996 1995
Statement of Operations Data:
Sales of oil and gas $ 66,615 $ 39,858 $ 67,172 $ 55,264 $ 45,773
Operating costs 22,028 17,828 22,407 17,587 18,264
General and administrative
expenses (G&A) 6,269 3,975 5,907 4,820 4,578
Depreciation, depletion &
amortization (DD&A) 12,294 10,080 10,138 7,323 6,847
Net income 18,006 3,879 19,260 17,546 12,203
Basic net income per share .82 .18 .88 .80 .56
Weighted average number of
shares outstanding 22,010 22,007 21,976 21,939 21,932
Balance Sheet Data:
Working capital $ 8,435 $ 9,081 $ 11,499 $ 7,850 $ 36,506
Total assets 207,649 173,804 177,724 176,403 117,722
Long-term debt 52,000 30,000 32,000 36,000 -
Shareholders' equity 116,213 106,924 111,871 101,009 92,060
Cash dividends per share .40 .40 .40 .40 .40
Operating Data:
Cash flow from operations 24,809 19,924 31,401 29,182 17,070
Capital expenditures
(excluding acquisitions) 9,122 6,981 18,597 9,333 7,518
Property/facility
acquisitions 33,605 2,991 - 75,613 7,554
Per BOE:
Sales price $ 13.07 $ 9.05 $ 14.71 $ 15.36 $ 13.48
Operating costs 4.33 4.05 4.92 4.92 5.41
G&A 1.23 .90 1.30 1.35 1.35
------ ------ ------ ------ ------
Cash flow 7.51 4.10 8.49 9.09 6.72
DD&A 2.42 2.29 2.23 2.05 2.03
------ ------ ------ ------ ------
Operating income $ 5.09 $ 1.81 $ 6.26 $ 7.04 $ 4.69
====== ====== ====== ====== ======
Production (BOE) 5,090 4,399 4,550 3,573 3,379
Proved Reserves Information:
Total BOE 112,541 92,609 101,043 102,116 78,068
Present value (PV10) of
estimated future cash
flow before income taxes $ 714,555 $ 113,811 $ 376,459 $ 634,579 $ 308,370
Year-end BOE price for
PV10 purposes 19.41 7.05 12.19 18.37 13.39
Other:
Return on average
shareholders' equity 16.5% 3.5% 18.1% 18.2% 13.6%
Return on average total assets 9.0% 2.2% 10.9% 13.3% 10.5%
Total debt/total debt
plus equity 30.9% 21.9% 22.2% 29.8% N/A
Year-end stock price $ 15 1/8 $14 3/16 $17 7/16 $ 14 3/8 $ 10 1/8
Year-end market
capitalization $332,920 $312,247 $383,510 $315,471 $222,061
15
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The following discussion provides information on the results of operations
for each of the three years ended December 31, 1999 and the financial condition,
liquidity and capital resources as of December 31, 1999. 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 net 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 1999 was $18 million, up 362% from $3.9 million in 1998,
but down 7% from $19.3 million in 1997. For the fourth quarter of 1999, net
income was $8.1 million, up 836% from a loss of $(1.1) million in the fourth
quarter of 1998 and up 72% from $4.7 million earned in the same 1997 period.
The improvements from 1998 are directly related to improved sales prices and
increased production levels, while maintaining good cost control.
The following table presents certain operating data for the years ended
December 31, 1999, 1998 and 1997:
1999 1998 1997
Net Production - BOE per day 13,946 12,053 12,465
Per BOE:
Average sales price $ 13.07 $ 9.05 $ 14.71
Operating costs(1) 3.81 3.46 4.24
Production taxes .52 .59 .68
Total operating costs 4.33 4.05 4.92
DD&A 2.42 2.29 2.23
G&A 1.23 .90 1.30
Interest expense .78 .44 .51
(1) Excluding production taxes.
Operating income from producing operations was $32.7 million in 1999, up
166% from $12.3 million in 1998, but down 7% from $35 million in 1997. This
dramatic fluctuation was a direct result of the change in oil prices. World
oil prices declined sharply in 1998, but gradually rebounded beginning in
early 1999. The average sales price/BOE received in 1999 was $13.07, up 44%
from $9.05 received in 1998, but down 11% from $14.71 received in 1997.
Postings for the Company's 13 degree API gravity crude oil started 1999 at
$6.50/bbl and improved during the year, ending 1999 at $19.75/bbl. As of
February 16, 2000, postings have increased to $23.50/bbl.
The improvement in operating income in 1999 from 1998 was also due to an
increase in oil and gas production during the year. Oil and gas production
averaged 13,946 BOE/day in 1999, up 16% from 12,053 BOE/day in 1998 and up 12%
from 12,465 BOE/day in 1997. These increases were due to the Company's
purchase of the Placerita oilfield properties in February 1999 which
currently produce approximately 3,200 net bbls/day.
16
The Company has integrated the Placerita properties into its operations
while maintaining excellent control of its operating costs. Operating costs
per BOE were $4.33 in 1999, up 7% from $4.05 in 1998, but down 12% from $4.92
in 1997. In 1998, in response to the drop in oil prices, the Company took a
number of steps to reduce costs and protect the cash flow of the Company.
Salary reductions were implemented, steam production from higher cost sources
was curtailed, well servicing activities were reduced and a number of wells
were shut-in, along with the implementation of other cost control measures.
As oil prices began to improve in 1999, salaries were restored, steaming and
well servicing activities were increased and a number of the shut-in wells
were put back on production. Production gradually increased during the year
from 13,573 BOE/D in February 1999 when the Placerita properties were added
to 14,736 BOE/D in the fourth quarter of 1999.
DD&A/BOE increased to $2.42 in 1999, up from $2.29 and $2.23 in 1998 and
1997, respectively. The increase was primarily due to the acquisition of the
producing leases and 42 megawatt cogeneration plant located in the Placerita
field and increased capital spending.
General
G&A increased 58% and 7%, respectively, to $6.3 million in 1999 from $4.0
million in 1998 and $5.9 million in 1997. On a per BOE basis, G&A increased to
$1.23 in 1999 from $.90 in 1998, but declined from $1.30 in 1997. The 1998 G&A
costs were unusually low in light of the severe market conditions faced by the
Company in early 1998 when 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 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. Legal costs
were also higher in 1999 due to a lawsuit involving TEORCO, a company Berry
purchased in 1988.
Interest expense in 1999 of $4.0 million was up significantly from $1.9
million in 1998 and $2.3 million in 1997. This increase was a direct result of
the financing of the Placerita acquisition in February 1999.
On December 31, 1998, the Company recorded a $1.8 million pre-tax
impairment charge related to non-producing properties in Kern County due to
the low year-end oil prices on that date.
The Company's effective income tax rate in 1999 was 21.4%, up from 9% in
1998, but down from 32% in 1997. The higher rate in 1999 was due primarily to
the increase in the price of oil compared to 1998, but lower than 1997 due to
increased EOR credits.
Financial Condition, Liquidity and Capital Resources
Working capital as of December 31, 1999 was $8.4 million, down from $9.1
million at December 31, 1998 and $11.5 million at December 31, 1997. Working
capital provided by operations was $30.4 million in 1999, compared to $18.2
million in 1998 and $32.9 million in 1997. Cash was used to fund the Company's
$9.1 million development program, which included $3.6 million for the drilling
of 21 new wells and a $3.1 million major turnaround on the Company's
38 megawatt cogeneration facility. Cash was also used to pay off $13 million
of the Company's long-term debt and to pay dividends of $8.8 million.
In February 1999, the Company purchased properties in the Placerita field
in Los Angeles County for $35 million which included six leases and two fee
properties with proved reserves of approximately 20 million barrels. The
acquisition also included a 42 megawatt cogeneration plant and two SO2
electricity sales contracts that expire in 2002 and 2009.
With the high oil prices that presently exist, the Company has put in
place a 2000 capital budget of approximately $15.8 million for the year, with
a focus on accelerating oil recovery on its core properties. A total of
57 new wells and 62 workovers are planned. The Company is also performing an
extensive 3-D seismic survey on a portion of its South Midway-Sunset
properties in the first quarter of 2000 at a cost of approximately $.8 million.
The Company anticipates a significant increase in production during the year
compared to 1999 levels. The Company expects to finance this
17
development through internally generated cash flow.
The total proved reserves at December 31, 1999 were 112.5 million BOE, up
21% from 92.6 million at December 31, 1998 and up 11% from 101 million BOE at
December 31, 1997. The increase from year-end 1998 was due primarily to the
purchase of the Placerita properties which added approximately 20 million
barrels and, to a lessor extent, the addition of 2.6 million BOE that were
previously deemed uneconomic at December 31, 1998.
The Company's present value of estimated future cash flows before income
taxes, discounted at 10%, was $715 million at December 31, 1999, up 527% from
$114 million at December 31, 1998 and up 90% from $376 million at December 31,
1997. The increase at December 31, 1999 compared to the prior two years was
primarily due to the increase in oil prices. The values were based on year-end
oil prices of $19.41, $7.05 and $12.19 for 1999, 1998 and 1997, respectively.
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 would not experience any material adverse
effects when the year 2000 arrived.
As part of the review, the Company determined that its accounting software
would have to be modified or replaced. The Company identified new software
that was represented to be Y2k compliant and implemented the packages in 1998
and 1999. The total cost of the software and hardware purchased to complete
the installation was approximately $.6 million. The Company evaluated all of
its other software, which is predominantly purchased from third party
providers, and determined that they were substantially Y2k compliant as of
the end of 1998.
The Company performed an evaluation of its computer hardware and
determined that, with only a few minor exceptions, it was Y2k compliant.
Minor upgrades were completed on some of the equipment to make them compliant
at no material cost to the Company. The Company worked with the contract
operator of the Company's three cogeneration facilities to ensure that all
equipment was 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'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 had 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. The Company communicated with
the financial institutions that are business partners of the Company.
When the year 2000 arrived, the Company experienced no problems and does
not anticipate any future problems related to Y2k that would materially
affect the Company's operations.
Future Developments
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 de-couple from natural gas prices. As of December 31, 1999, the
Company's sales price for electricity generated from the three cogeneration
plants owned by the Company correlates directly with natural gas prices.
Therefore, the Company's net steam costs are fairly consistent between
quarters and years. Beginning upon full deregulation, now believed to occur
in 2001, electricity prices will be determined by not only the cost of natural
gas, but also the cost of coal, hydroelectric power, nuclear power and other
sources of power. In addition, changes in power supply and demand may make
electricity prices more volatile than in the past. The Company is reviewing
its future fuel supply and power sales options to maximize the cash flow of
these assets while reducing the potential volatility of the related
steam costs.
18
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, competition, environmental
risks, litigation uncertainties, drilling, development and operating risks,
uncertainties about the estimates of reserves, Y2k non-compliance by the
vendors, customers, the Company, etc. and government regulation.
19
Item 8. Financial Statements and Supplementary Data
BERRY PETROLEUM COMPANY
Index to Financial Statements and
Supplementary Data
Page
Report of PricewaterhouseCoopers LLP, Independent Accountant ....... 21
Balance Sheets at December 31, 1999 and 1998 ....................... 22
Statements of Operations for the
Years Ended December 31, 1999, 1998 and 1997 ..................... 23
Statements of Shareholders' Equity for the
Years Ended December 31, 1999, 1998 and 1997 ..................... 24
Statements of Cash Flows for the
Years Ended December 31, 1999, 1998 and 1997 ..................... 25
Notes to the Financial Statements .................................. 26
Supplemental Information About Oil & Gas
Producing Activities ............................................. 37
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.
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
operations and shareholders' equity and of cash flows present fairly, in all
material respects, the financial position of Berry Petroleum Company (the
"Company") at December 31, 1999 and 1998, and the results of their operations
and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally
accepted in the United States. These financial statements are the
responsibility of the Company's management; our responsibility is to express
an opinion on these financial statements based on our audits. We conducted
our audits of these statements in accordance with auditing standards generally
accepted in the United States 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.
PRICEWATERHOUSECOOPERS LLP
February 18, 2000
Los Angeles, California
21
BERRY PETROLEUM COMPANY
Balance Sheets
December 31, 1999 and 1998
(In Thousands, Except Share Information)
1999 1998
ASSETS
Current assets:
Cash and cash equivalents $ 980 $ 7,058
Short-term investments available for sale 596 710
Accounts receivable 15,303 5,495
Prepaid expenses and other 2,080 4,049
-------- --------
Total current assets 18,959 17,312
Oil and gas properties (successful efforts basis),
buildings and equipment, net 186,519 155,571
Other assets 2,171 921
-------- --------
$ 207,649 $ 173,804
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 7,203 $ 5,491
Accrued liabilities 1,999 2,108
Federal and state income taxes payable 1,322 632
-------- --------
Total current liabilities 10,524 8,231
Long-term debt 52,000 30,000
Deferred income taxes 28,912 28,649
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; 21,112,334 shares issued
and outstanding (21,109,729 in 1998) 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 53,487 53,400
Retained earnings 62,506 53,304
-------- --------
Total shareholders' equity 116,213 106,924
-------- --------
$ 207,649 $ 173,804
======== ========
The accompanying notes are an integral part of these financial statements.
22
BERRY PETROLEUM COMPANY
Statements of Operations
Years ended December 31, 1999, 1998 and 1997
(In Thousands, Except Per Share Data)
1999 1998 1997
Revenues:
Sales of oil and gas $ 66,615 $ 39,858 $ 67,172
Interest and dividend income 674 805 643
Gain/(loss) on sale of assets 21 (716) 1,093
Other income (expense), net 165 (48) 87
------- ------- -------
67,475 39,899 68,995
------- ------- -------
Expenses:
Operating costs 22,028 17,828 22,407
Depreciation, depletion & amortization 12,294 10,080 10,138
Interest expense 3,973 1,939 2,302
Impairment of properties - 1,827 -
General and administrative 6,269 3,975 5,907
------- ------- -------
44,564 35,649 40,754
------- ------- -------
Income before income taxes 22,911 4,250 28,241
Provision for income taxes 4,905 371 8,981
------- ------- -------
Net income $ 18,006 $ 3,879 $ 19,260
======= ======= =======
Basic net income per share $ .82 $ .18 $ .88
======= ======= =======
Diluted net income per share $ .82 $ .18 $ .87
======= ======= =======
Weighted average number of shares of
capital stock outstanding (used to
calculate basic net income per share) 22,010 22,007 21,976
Effect of dilutive securities:
Stock options 32 25 173
Other 7 5 16
------- ------- -------
Weighted average number of shares of
capital stock used to calculate
diluted net income per share 22,049 22,037 22,165
======= ======= =======
The accompanying notes are an integral part of these financial statements.
23
BERRY PETROLEUM COMPANY
Statements of Shareholders' Equity
Years Ended December 31, 1999, 1998 and 1997
(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, 1997 $ 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
Stock options
exercised - - 2 - 2
Deferred director
fees - stock
compensation - - 85 - 85
Cash dividends
declared -
$.40 per share - - - (8,804) (8,804)
Net income - - - 18,006 18,006
----- ----- ------- ------- -------
Balances at
December 31,
1999 $ 211 $ 9 $ 53,487 $ 62,506 $ 116,213
===== ===== ======= ======= =======
The accompanying notes are an integral part of these financial statements.
24
BERRY PETROLEUM COMPANY
Statements of Cash Flows
Years Ended December 31, 1999, 1998 and 1997
(In Thousands)
1999 1998 1997
Cash flows from operating activities:
Net income $ 18,006 $ 3,879 $ 19,260
Depreciation, depletion and
amortization 12,294 10,080 10,138
Gain on sale of assets (21) (55) (1,093)
Impairment of properties - 1,827 -
Increase in deferred income
tax liability 263 2,740 4,917
Other, net (187) (260) (302)
------- ------- -------
Net working capital provided by
operating activities 30,355 18,211 32,920
Decrease (increase) in current
assets other than cash,
cash equivalents and short-term
investments (7,839) 1,425 2,039
Increase (decrease) in current
liabilities other than notes
payable 2,293 288 (3,558)
------- ------- -------
Net cash provided by
operating activities 24,809 19,924 31,401
------- ------- -------
Cash flows from investing activities:
Capital expenditures, excluding
property acquisitions (9,122) (6,981) (18,597)
Property/facility acquisitions (33,605) (2,991) -
Proceeds from sale of assets 21 350 1,892
Purchase of short-term investments (611) - (14)
Maturities of short-term investments 725 8 -
Restricted cash deposit - - 2,570
Contract purchases (1,028) (240) -
Other, net - - (50)
------- ------- -------
Net cash used in investing activities (43,620) (9,854) (14,199)
------- ------- -------
Cash flows from financing activities:
Proceeds from issuance of
long-term debt 35,000 - 3,000
Payment of long-term debt (13,000) (2,000) (7,000)
Payment of short-term notes payable - - (6,900)
Dividends paid (8,804) (8,804) (8,792)
Other, net (463) 36 276
------- ------- -------
Net cash provided by (used in)
financing activities 12,733 (10,768) (19,416)
------- ------- -------
Net decrease in cash and cash
equivalents (6,078) (698) (2,214)
Cash and cash equivalents at
beginning of year 7,058 7,756 9,970
------- ------- -------
Cash and cash equivalents at
end of year $ 980 $ 7,058 $ 7,756
======= ======= =======
Supplemental disclosures of
cash flow information:
Interest paid $ 4,546 $ 1,924 $ 2,319
======= ======= =======
Income taxes paid $ 4,079 $ 270 $ 4,280
======= ======= =======
The accompanying notes are an integral part of these financial statements.
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 and exploration of crude oil and natural
gas. Substantially all of the Company's oil and gas reserves are located in
California. Approximately 99% of the Company's production is 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 accounting
principles generally accepted in the United States requires Management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
2. Summary of Significant Accounting Policies
Cash and cash equivalents
The Company considers all highly liquid investments purchased with a
remaining maturity of three months or less to be cash equivalents.
Short-term investments
All short-term investments are classified as available for sale.
Short-term investments consist principally of United States treasury notes
and corporate notes with remaining maturities of more than three months at
date of acquisition. Such investments are stated at cost, which approximates
market. The Company utilizes specific identification in computing realized
gains and losses on investments sold.
Oil and gas properties, buildings and equipment
The Company accounts for its oil and gas exploration and development costs
using the successful efforts method. Under this method, costs to acquire and
develop proved reserves and to drill and complete exploratory wells that find
proved reserves are capitalized and depleted over the remaining life of the
reserves using the units-of-production method. Exploratory dry hole costs and
other exploratory costs, including geological and geophysical costs, are
charged to expense when incurred. The costs of carrying and retaining
unproved properties are also expensed when incurred.
Depletion of oil and gas producing properties is computed using the units-
of-production method. Depreciation of lease and well equipment, including
cogeneration facilities and other steam generation equipment and facilities, is
computed using the units-of-production method or on a straight-line basis over
estimated useful lives ranging from 10 to 20 years. The estimated costs, net
of salvage value, of plugging and abandoning oil and gas wells and related
facilities are accrued using the units-of-production method and are taken into
account in determining DD&A expense. Buildings and equipment are recorded at
cost. Depreciation is provided on a straight-line basis over estimated useful
lives ranging from 5 to 30 years for buildings and improvements and 3 to 10
years for machinery and equipment. Assets are grouped at the field level and
if it is determined that the book value of long-lived assets cannot be
recovered by estimated future undiscounted cash flows, they 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.
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 California refiners 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 10 to the Company's financial statements.
Income Taxes
Income taxes are provided based on the liability method of accounting
pursuant to SFAS No. 109, "Accounting for Income Taxes." The provision for
income taxes is based on pre-tax financial accounting income. Deferred tax
assets and liabilities are recognized for the future expected tax consequences
of temporary differences between income tax and financial reporting, and
principally relate to differences in the tax 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.
Reclassifications
Certain reclassifications have been made to the 1998 financial statements
to conform with the 1999 presentation.
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 $151 thousand and
$6.9 million at December 31, 1999 and 1998, respectively, are stated at cost,
which approximates market.
The Company's short-term investments available for sale at December 31,
1999 and 1998 consist of one United States treasury note. All of the short-
term investments at December 31, 1999 mature in less than one year. The
carrying value of the Company's long-term debt is assumed to approximate its
fair value since it is carried at current interest rates. For the three years
ended December 31, 1999, realized and unrealized gains and losses were
insignificant to the financial statements. A United States treasury note
with a market value of $.6 million is pledged as collateral to the California
State Lands Commission as a performance bond on the Company's Montalvo
properties.
To protect the Company's revenues from potential price declines, the
Company entered into bracketed zero cost collar hedge contracts with
California refiners covering 6,500 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 contracts expire on December 31, 2000.
4. Concentration of Credit Risks
The Company sells oil, gas and natural gas liquids to pipelines,
refineries and major oil companies and electricity to major utility
companies. Credit is extended based on an evaluation of the customer's
financial condition. For the three years ended December 31, 1999, the
Company has experienced no credit losses on the sale of oil, gas, natural
gas liquids or electricity.
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, 1999, the
Company has not incurred losses related to these investments.
The following summarizes the accounts receivable balances at December 31,
1999 and 1998 and sales activity with significant customers for each of the
years ended December 31, 1999, 1998 and 1997 (in thousands):
Sales
Accounts Receivable For the Year Ended December 31,
Customer December 31, 1999 December 31, 1998 1999 1998 1997
Oil & Gas Sales:
A $ 3,975 $ 794 $ 30,289 $ 12,409 $ 19,482
B 2,040 454 15,064 6,282 7,119
C 1,627 435 11,467 7,281 23,804
D 406 601 7,890 10,785 12,875
------- ------ ------- ------- -------
$ 8,048 $ 2,284 $ 64,710 $ 36,757 $ 63,280
======= ====== ======= ======= =======
Electricity Sales:
E $ 2,034 $ - $ 16,013 $ - $ -
F 3,141 2,493 15,603 15,624 16,961
------- ------ ------- ------- -------
$ 5,175 $ 2,493 $ 31,616 $ 15,624 $ 16,961
======= ====== ======= ======= =======
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):
1999 1998
Oil and gas:
Proved properties:
Producing properties, including
intangible drilling costs $ 146,616 $ 133,372
Lease and well equipment 123,026 93,637
-------- --------
269,642 227,009
Less accumulated depreciation,
depletion and amortization 85,319 73,577
-------- --------
184,323 153,432
-------- --------
Commercial and other:
Land 170 170
Buildings and improvements 4,072 4,007
Machinery and equipment 4,211 3,775
-------- --------
8,453 7,952
Less accumulated depreciation 6,257 5,813
-------- --------
2,196 2,139
-------- --------
$ 186,519 $ 155,571
======== ========
The following sets forth costs incurred for oil and gas property acquisition,
exploration and development activities, whether capitalized or expensed (in
thousands):
1999 1998 1997
Acquisition of
properties/facilities(1) $ 34,167 $ 2,991 $ -
Exploration - - -
Development 9,195 6,896 18,172
------- ------- -------
$ 43,362 $ 9,887 $ 18,172
======= ======= =======
(1) Includes cogeneration facility costs and certain closing
and consultant costs related to the acquisitions, but
excluding electricity contract costs.
The Company completed the Placerita acquisition in 1999 for a purchase
price of approximately $35 million, including the purchase of a 42 megawatt
cogeneration facility and related electricity contracts. These properties had
proved reserves of approximately 20 million barrels upon acquisition. In 1998,
the Company completed an acquisition with proved reserves of approximately 1
million barrels and a steam contract located adjacent to the Company's core
South Midway-Sunset producing properties.
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):
1999 1998 1997
Sales to unaffiliated parties $ 66,615 $ 39,858 $ 67,172
Production costs (22,028) (17,828) (22,407)
Depreciation, depletion and
amortization (11,921) (9,686) (9,731)
------- ------- -------
32,666 12,344 35,034
Income tax expenses (8,584) (3,223) (10,870)
------- ------- -------
Results of operations from producing
and exploration activities $ 24,082 $ 9,121 $ 24,164
======= ======= =======
6. Debt Obligations
1999 1998
Long-term debt for the years ended December 31 (in thousands):
Revolving bank facility $ 52,000 $ 30,000
======= =======
On July 22, 1999, the Company executed an Amended and Restated Credit
Agreement (the Agreement) with a banking group, which consists of four banks,
for a $150 million five-year unsecured bullet loan. At December 31, 1999 and
1998, the Company had $52 and $30 million, respectively, outstanding under
the Agreement. The maximum amount available is subject to an annual
redetermination of the borrowing base in accordance with the lender's
customary procedures and practices. Both the Company and the banks have
bilateral rights to one additional redetermination each year. The revolving
period is scheduled to terminate on January 21, 2004. Interest on amounts
borrowed is charged at the lead bank's base rate or at London Interbank
Offered Rates (LIBOR) plus 75 to 150 basis points, depending on the ratio
of outstanding credit to the borrowing base. The weighted average interest
rate on outstanding borrowings at December 31, 1999 was 6.83%. 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. Previously, on January 21, 1999, the
Company amended its existing credit agreement with its lead bank primarily
to increase the borrowing base to $110 million and add two additional
banks to its syndication.
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 November 1999, the Company adopted a Shareholder Rights Agreement and
declared a dividend distribution of one Right for each outstanding share of
Capital Stock on December 8, 1999. Each Right, when exercisable, entitles the
holder to purchase one one-hundredth of a share of a Series B Junior
Participating Preferred Stock, or in certain cases other securities, for
$38.00. The exercise price and number of shares issuable are subject to
adjustment to prevent dilution. The Rights would become exercisable, unless
earlier redeemed by the Company, 10 days following a public announcement that
a person or group has acquired, or obtained the right to acquire, 20% or more
of the outstanding shares of Common Stock or, 10 business days following the
commencement of a tender or exchange offer for such outstanding shares which
would result in such person or group acquiring 20% or more of the outstanding
shares of Common Stock, either event occurring without the prior consent of
the Company.
The Rights will expire on December 8, 2009 or may be redeemed by the
Company at $.01 per Right prior to that date unless they have theretofore
become exercisable. The Rights do not have voting or dividend rights, and
until they become exercisable, have no diluting effect on the earnings of
the Company. A total of 250,000 shares of the Company's Preferred Stock has
been designated Series B Junior Participating Preferred Stock and reserved
for issuance upon exercise of the Rights. This Shareholder Rights Agreement
replaces the Shareholder Rights Agreement approved in December 1989 which
expired on December 8, 1999.
In conjunction with the acquisition of the Tannehill assets in 1996, the
Company issued a Warrant Certificate to the beneficial owners of Tannehill Oil
Company. This Warrant authorizes the purchase of 100,000 shares of Berry
Petroleum Company Class A Common Stock until November 8, 2003 at $14.06 per
share. All the warrants are currently outstanding and the underlying shares
will not be registered under the Securities Act of 1933.
The Company issued 2,745, 15,268, and 47,621 shares in 1999, 1998 and
1997, respectively, through its stock option plans.
At December 31, 1999, 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.
31
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
8. Income Taxes
The Provision for income taxes consists of the following (in thousands):
1999 1998 1997
Current:
Federal $ 2,661 $ (716) $ 3,502
State 928 (881) 995
------ ------ ------
3,589 (1,597) 4,497
------ ------ ------
Deferred:
Federal 1,979 1,968 3,940
State (663) - 544
------ ------ ------
1,316 1,968 4,484
------ ------ ------
Total $ 4,905 $ 371 $ 8,981
====== ====== ======
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):
1999 1998
Deferred tax asset
Federal benefit of state taxes $ 1,012 $ 1,514
Credit/deduction carryforwards 2,944 2,481
Other, net 1,078 (479)
------- -------
5,034 3,516
------- -------
Deferred tax liability
Depreciation and depletion (29,581) (26,143)
State taxes (4,142) (4,545)
Other, net (74) (275)
------- -------
(33,797) (30,963)
------- -------
Net deferred tax liability $ (28,763) $ (27,447)
======= =======
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:
1999 1998 1997
Tax computed at statutory federal rate 35.0% 34.0% 35.0%
State income taxes, net of federal benefit .3 2.0 3.5
Tax credits (12.9) (24.3) (7.6)
Other (1.0) (3.0) .9
----- ----- -----
Effective tax rate 21.4% 8.7% 31.8%
===== ===== =====
The Company has approximately $4.5 million of federal and $2.6 million of
state enhanced oil recovery (EOR) tax credit carryforwards available to reduce
future income taxes. The EOR credits will expire in the years 2013 and 2014,
if not previously utilized. The Company also has $.2 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 2001.
9. Contingencies
The Company is a cross-defendant in litigation pending in the Los Angeles
County Superior Court. The original lawsuit was filed in June 1996, and the
Company was served as a Doe cross-defendant in June 1997. The complaint
involves an oil and gas lease located in Los Angeles County and seeks to
recover approximately $.6 million in clean up costs allegedly incurred by the
plaintiff/lessor after the lease that dated back to the late 1940's was
terminated by the then lessee. Substantially all of the lessees in the chain
of title from the late 1940's to the date of termination were named as
defendants. The cross-complaint by Placerita Oil Company, Inc. ("POCI"), the
last of the lessees, seeks indemnification from the other lessees in the
chain of title as to the plaintiff's claims. Although the Company was never
a lessee in the chain of title, Berry acquired all of the stock of one of the
lessees (TEORCO) that had been in the chain of title in prior years. TEORCO
assigned the leases to POCI approximately two years prior to Berry's acquiring
the stock of TEORCO. POCI's cross-complaint also seeks an unknown amount,
but which could be as much as $49 million in damages from TOSCO Corporation
and from TEORCO, the entity that in 1986 assigned to POCI the lease and two
other leases, on the basis of alleged fraud by TOSCO, et al. in overstating
the oil and gas reserves to POCI. TOSCO is the same entity that sold the
stock of its subsidiary, TEORCO, to Berry in 1988. Berry has potential
successor liability because of its acquisition of the stock of TEORCO. In
the third and fourth quarter of 1999, the scope of the litigation
broadened substantially and required increasing resources to defend. The
Company is vigorously defending itself and has incurred significant legal
expenses that impact general and administrative expenses. The case is
currently being tried before a jury with a likely initial outcome in the
first quarter of 2000. Although Management believes it has a strong defense
in the lawsuit, the ultimate outcome cannot be determined at this time.
Therefore, no receivable or liability has been recorded by the Company.
33
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
10. Stock Option and Stock Appreciation Rights Plans
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 and June 2, 1997, 434,000, 200,000
and 40,000 options, respectively, were issued to certain key employees at an
exercise price of $12.50, $19.375 and $15.50 per share, respectively, which
was the closing market price of the Company's Class A Common Stock on the
New York Stock Exchange on those dates. The options vest 25% per year for
four years. No employee options were issued in 1999. The 1994 Plan also
allows for option grants to the Board of Directors under a formula plan
whereby all non-employee Directors are eligible to receive 5,000 options
annually on December 2 at the fair value on the date of grant. The options
granted to the non-employee Directors vest immediately. Through the 1994 Plan,
40,000, 45,000 and 55,000 options, respectively, were issued on December 2,
1999, 1998 and 1997, (5,000 options to each of the non-employee Directors each
year) at an exercise price of $14.0625, $12.625 and $18.9375 per share,
respectively.
The Company applies APB No. 25 and related interpretations in accounting
for its stock option plans. The options issued per the 1994 Plan were issued
at market price. Compensation recognized related to the 1994 Plan was $0 in
1999, $.04 million in 1998 and $.5 million in 1997.
The Company had 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 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). 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. All options and SARs outstanding under the 1987
plans were exercised in early 1998. Total compensation expense recognized
for the SAR Plan for the prior three years was insignificant.
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:
1999 1998 1997
Dividend - $/year $ .40 $ .40 $ .40
Expected option life - years 4 4 4
Volatility 34.24% 28.13% 26.03%
Risk-free interest rate 6.33% 4.68% 5.48%
34
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
10. 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):
1999 1998 1997
Net income as reported $ 18,006 $ 3,879 $ 19,260
Pro forma 17,343 3,244 19,185
Net income per share as reported .82 .18 .88
Pro forma .79 .15 .87
The following is a summary of stock-based compensation activity for the
years 1999, 1998 and 1997.
1999 1998 1997
Options Options SARs Options SARs
Balance outstanding, --------- -------- ----- -------- -----
January 1 1,227,630 924,429 1,120 861,929 9,200
Granted 40,000 504,000 - 270,000 -
Exercised (22,000) (75,799) (1,120) (196,800) (8,080)
Canceled/expired (25,000) (125,000) - (10,000) -
--------- -------- ------ -------- ------
Balance outstanding,
December 31 1,220,630 1,227,630 - 924,429 1,120
========= ========= ====== ======== ======
Balance exercisable at
December 31 697,630 449,880 - 256,929 1,120
========= ========= ====== ======== ======
Available for future grant 666,800 681,800 - 60,800 -
========= ========= ====== ======== ======
Exercise price-range $ 14.125 $ 9.80 $ 9.80 $ 9.80 $ 9.80
to 14.25 to 19.375 to 19.375 to 10.00
Weighted average remaining
contractual life (years) 8 9 - 9 1
Weighted average fair value
per option granted
during the year $ 5.14 $ 2.82 N/A $ 4.56 N/A
Weighted average option exercise price information for the years 1999, 1998
and 1997 as follows:
1999 1998 1997
Outstanding at January 1 $ 14.18 $ 14.71 $ 12.61
Granted during the year 14.06 12.83 18.75
Exercised during the year 12.40 11.42 11.03
Expired during the year 16.69 14.34 14.00
Outstanding at December 31 14.15 14.18 14.71
Exercisable at December 31 14.21 14.17 13.09
35
BERRY PETROLEUM COMPANY
Notes to the Financial Statements
11. Retirement Plan
The Company sponsors a defined contribution retirement or thrift plan
(401(k) Plan) to assist all employees in providing for retirement or other
future financial needs. Employee contributions (up to 6% of earnings) are
matched by the Company dollar for dollar. Effective November 1, 1992, the
401(k) Plan was modified to provide for increased Company matching of
employee contributions whereby the monthly Company matching contributions
will range from 6% to 9% of eligible participating employee earnings, if
certain financial targets are achieved. The Company's contributions to the
401(k) Plan were $.3 million in 1999, $.2 million in 1998 and $.3 million in
1997.
12. Quarterly Financial Data (unaudited)
The following is a tabulation of unaudited quarterly operating results for
1999 and 1998 (in thousands, except per share data):
Basic net Diluted net
Operating Gross Net Income (loss) Income (loss)
1999 Revenues Profit Income (loss) Per Share Per Share
------- ---------- -------- ------------ ---------- ----------
First Quarter $ 9,213 $ 1,998 $ 544 $ .02 $ .02
Second Quarter 14,463 6,404 3,247 .15 .15
Third Quarter 19,132 10,222 6,099 .28 .28
Fourth Quarter 23,767 14,002 8,116 .37 .37
------- ------- ------- ------ ------
$ 66,575 $ 32,626 $ 18,006 $ .82 $ .82
======= ======= ======= ====== ======
1998
-------
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
======= ======= ======= ====== ======
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, 1999,
1998 and 1997. Such estimates are subject to numerous uncertainties inherent
in the estimation of quantities of proved reserves and in the projection of
future rates of production and the timing of development expenditures.
These estimates do not include probable or possible reserves. The information
provided does not represent Management's estimate of the Company's expected
future cash flows or value of proved oil and gas reserves.
Changes in estimated reserve quantities
The net interest in estimated quantities of proved developed and
undeveloped reserves of crude oil and natural gas at December 31, 1999,
1998 and 1997, and changes in such quantities during each of the years then
ended were as follows (in thousands):
1999 1998 1997
Oil Gas Oil Gas Oil Gas
Mbbls Mmcf Mbbls Mmcf Mbbls Mmcf
Proved developed and
undeveloped reserves:
Beginning of year 91,933 4,060 100,454 3,531 101,336 4,682
Revision of previous
estimates 3,126 40 (4,894) 774 3,647 (869)
Production (5,060) (180) (4,359) (245) (4,503) (282)
Sale of reserves
in place - - - - (26) -
Purchase of reserves
in place 21,889 - 732 - - -
------- ----- ------- ----- ------- -----
End of year 111,888 3,920 91,933 4,060 100,454 3,531
======= ===== ======= ===== ======= =====
Proved developed reserves:
Beginning of year 83,532 1,604 86,858 1,457 76,358 2,608
======= ===== ======= ===== ======= =====
End of year 86,717 1,371 83,532 1,604 86,858 1,457
======= ===== ======= ===== ======= =====
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):
1999 1998 1997
Future cash inflows $ 2,208,964 $ 656,607 $ 1,232,749
Future production and
development costs (647,720) (388,546) (421,305)
Future income tax expenses (502,951) (33,577) (246,668)
--------- -------- ---------
Future net cash flows 1,058,293 234,484 564,776
10% annual discount for estimated
timing of cash flows (561,811) (127,967) (297,182)
--------- -------- ---------
Standardized measure of discounted
future net cash flows $ 496,482 $ 106,517 $ 267,594
========= ======== =========
Pre-tax standardized measure of
discounted future net cash flows $ 714,555 $ 113,811 $ 376,459
========= ======== =========
Average sales prices at December 31:
Oil ($/bbl) $ 19.41 $ 7.05 $ 12.19
Gas ($/mcf) $ 2.11 $ 2.10 $ 2.33
Changes in standardized measure of discounted future net cash flows from
proved oil and gas reserves (in thousands):
1999 1998 1997
Standardized measure - beginning
of year $ 106,517 $ 267,594 $ 420,559
-------- -------- --------
Sales of oil and gas produced,
net of production costs (44,587) (22,030) (44,765)
Revisions to estimates of proved reserves:
Net changes in sales prices
and production costs 440,729 (216,265) (259,026)
Revisions of previous quantity estimates 20,919 (8,400) 14,014
Change in estimated future development
costs (24,709) (17,262) (1,775)
Purchases of reserves in place 169,147 1,597 -
Sales of reserves in place - - (244)
Development costs incurred during
the period 9,122 6,728 18,597
Accretion of discount 11,381 37,539 63,458
Income taxes (203,514) 46,293 109,780
Other 11,477 10,723 (53,004)
-------- -------- --------
Net increase (decrease) 389,965 (161,077) (152,965)
-------- -------- --------
Standardized measure - end of year $ 496,482 $ 106,517 $ 267,594
======== ======== ========
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 "Security Ownership of Directors and Management"
and "Principal Shareholders" in the Company's definitive proxy statement to be
filed pursuant to Regulation 14A no later than 120 days after the close of its
fiscal year.
Compliance with Section 16(a) of the Securities Exchange Act of 1934
Section 16(a) of the Securities Exchange Act of 1934 and related
Securities and Exchange Commission rules require that Directors and
Executive Officers report to the Securities and Exchange Commission changes
in their beneficial ownership of Berry stock, and that any late filings be
disclosed. Based solely on a review of the copies of such forms furnished
to the Company, or written representations that no Form 5 was required, the
Company believes that all Section 16(a) filing requirements were complied
with.
Item 13. Certain Relationships and Related Transactions
The information called for by Item 13 is incorporated by reference from
information under the caption "Certain Relationships and Related
Transactions" in the Company's definitive proxy statement to be filed pursuant
to Regulation 14A no later than 120 days after the close of its fiscal year.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
A. Financial Statements and Schedules
See Index to Financial Statements and Supplementary Data in Item 8.
B. Reports on Form 8-K
None
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 B Junior Participating Preferred Stock
(filed as Exhibit A to the Registrant's Registration
Statement on Form 8-A12B on December 7, 1999,
File No. 778438-99-000016)
3.4 Registrant's First Amendment to Restated Bylaws dated 43
August 31, 1999
4.1* Rights Agreement between Registrant and ChaseMellon
Shareholder Services, L.L.C. dated as of December 8, 1999
(filed by the Registrant on Form 8-A12B on December 7, 1999,
File No. 778438-99-000016)
10.1* Description of Cash Bonus Plan of Berry Petroleum Company
(filed as Exhibit 10.1 to the Registrant's Annual Report
on Form 10-K for the year ended December 31, 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 Amended and Restated Credit Agreement, dated as of July 45
22, 1999, by and between the Registrant and Bank of
America, N.A., the First National Bank of Chicago and other
financial institutions.
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)
40
Exhibits (cont'd)
Exhibit No. Description of Exhibit Page
10.13* Amended and Restated 1994 Stock Option Plan (filed as
Exhibit 10.13 in Registrant's Form 10-K filed on March 16,
1999, File No. 1-9735)
23.1 Consent of PricewaterhouseCoopers LLP 112
23.2 Consent of DeGolyer and MacNaughton 113
27.** Financial Data Schedule
99.1 Undertaking for Form S-8 Registration Statements 115
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
41
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 February 28, 2000.
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
Director, President and Chief Financial Officer (Principal
Chief Executive Officer (Principal Financial Officer) Accounting
Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities on the dates so indicated.
Name Office Date
/s/ Jerry V. Hoffman Chairman of the Board, Director, February 25, 2000
Jerry V. Hoffman President & Chief Executive Officer
/s/ William F. Berry Director February 25, 2000
William F. Berry
/s/ Ralph B. Busch, III Director February 25, 2000
Ralph B. Busch, III
/s/ William E. Bush, Jr. Director February 25, 2000
William E. Bush, Jr.
/s/ J. Herbert Gaul, Jr. Director February 25, 2000
J. Herbert Gaul, Jr.
/s/ John A. Hagg Director February 25, 2000
John A. Hagg
/s/ Thomas J. Jamieson Director February 25, 2000
Thomas J. Jamieson
/s/ Roger G. Martin Director February 25, 2000
Roger G. Martin
/s/ Martin H. Young, Jr. Director February 25, 2000
Martin H. Young, Jr.
42