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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 [Fee Required]
For the fiscal year ended December 31, 1998
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [No Fee Required]
For the transition period from to
Commission File Number: 1-13515
FOREST OIL CORPORATION
(Exact name of registrant as specified in its charter)
State of incorporation: New York I.R.S. Employer Identification No. 25-0484900
1600 Broadway
Suite 2200
Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 303-812-1400
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Title of Each Class
-------------------
Common Stock, Par Value $.10 Per Share
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.
[x] Yes [ ] 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 the 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. [ ]
The aggregate market value of the voting stock held by non-affiliates of
the registrant was approximately $167,636,694 as of February 28, 1999 (based
on the last reported sale price of such stock on the New York Stock Exchange
Composite Tape).
There were 44,647,295 shares of the registrant's Common Stock, Par Value
$.10 Per Share outstanding as of February 28, 1999.
Document incorporated by reference: Proxy Statement of Forest Oil
Corporation relative to the Annual Meeting of Shareholders to be held on May
12, 1999, which is incorporated into Part III of this Form 10- K.
TABLE OF CONTENTS
Page No.
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PART I
Item 1. Business 1
Item 2. Properties 17
Item 3. Legal Proceedings 23
Item 4. Submission of Matters to a Vote of Security Holders 23
Item 4A. Executive Officers of Forest 23
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 25
Item 6. Selected Financial and Operating Data 26
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations 28
Item 7a. Quantitative and Qualitative Disclosures About Market Risk 40
Item 8. Financial Statements and Supplementary Data 41
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure 41
PART III
Item 10. Directors and Executive Officers of the Registrant 81
Item 11. Executive Compensation 81
Item 12. Security Ownership of Certain Beneficial Owners and Management 81
Item 13. Certain Relationships and Related Transactions 81
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 81
PART I
ITEM 1. BUSINESS
THE COMPANY
Forest Oil Corporation and its subsidiaries are engaged in the acquisition,
exploration, development, production and marketing of natural gas and liquids
in North America. Forest was incorporated in New York in 1924, the successor
to a company formed in 1916, and has been a publicly held company since 1969.
Since 1995 the Anschutz Corporation, a private Denver-based corporation, has
invested almost $175 million in Forest and currently owns approximately 40%
of our common stock.
Forest's principal reserves and producing properties are located in the
onshore and offshore Gulf of Mexico region, West Texas, Wyoming and western
Canada. Approximately 72% of our oil and gas reserves are in the United
States and 28% are in Canada. Approximately 70% of total 1998 production was
in the United States and approximately 30% was in Canada. We currently
operate 30 offshore platforms in the Gulf of Mexico, and 1998 production from
this area accounted for approximately 36% of our total production on an MCFE
basis. (An MCF is one thousand cubic feet of natural gas. MMCF is used to
designate one million cubic feet of natural gas and BCF refers to one billion
cubic feet of natural gas. MCFE means thousands of cubic feet of natural gas
equivalents, using a conversion ratio of one barrel of liquids to six MCF of
natural gas. BCFE means billions of cubic feet of natural gas equivalents.
With respect to liquids, the term BBL means one barrel of liquids whereas
MBBLS is used to designate one thousand barrels of liquids. The term liquids
is used to describe oil, condensate and natural gas liquids.)
Forest's estimated proved reserves were 775 BCFE at December 31, 1998, of
which approximately 73% was natural gas. This represents an increase of 47%
compared to estimated proved reserves of 526 BCFE at December 31, 1997 of
which approximately 72% was natural gas.
Forest operates from production offices located in Lafayette, Louisiana;
Denver, Colorado; and Calgary, Alberta. Forest's corporate headquarters are
located in Denver, Colorado. On December 31, 1998 Forest had 274 employees,
of whom 211 were salaried and 63 were hourly. Of the salaried employees, 17
were employed by ProMark, our marketing and processing business. For
financial information relating to our industry and operational segments, see
Note 13 of Notes to Consolidated Financial Statements.
OPERATING STRATEGY
Forest's strategy is to focus on exploration, development and acquisition of
oil and gas producing properties located in selected areas in North America.
We concentrate on areas where we have expertise and experience, and where we
believe significant exploration potential exists within a well-defined
marketing infrastructure. We intend to pursue this strategy through the
following initiatives:
DIVERSIFY NORTH AMERICAN OPERATIONS. Through our acquisitions and capital
programs in Canada, we have significantly diversified our operations and
added long-lived reserves and production assets to our development portfolio.
Expansion into Canada has also provided diversification to the exploration
portfolio through exposure to exploratory plays with different geological and
geophysical characteristics. We further diversified in 1998 with a
significant acquisition onshore in South Louisiana. This acquisition added
substantial development projects to our portfolio, as well as deep
exploratory opportunities similar to those we have offshore in the Gulf of
Mexico.
In addition, we believe that our geographic positions provide attractive
natural gas market diversification. We believe that this diversification
could benefit our operating margins as improvements in the infrastructure of
the North American gas transportation system create price differentials that
are more closely related to proximity to markets rather than the availability
of transportation. Supporting this belief is the fact that the average price
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differential between Canadian spot gas prices and Henry Hub spot gas prices
for the three months ended December 31, 1998 decreased by approximately $1.41
U.S. per MMBTU compared to the same period in the prior year.
INCREASE RESERVES THROUGH FOCUSED EXPLORATION. Forest explores as a source of
growth, targeting opportunities that benefit from the selective use of
advanced technologies in mature basins (such as new 3-D seismic processing
techniques and production and completion methods) as well as those
opportunities in emerging basins which may not require new technology. Since
improving our capitalization, we have accelerated the exploration of our
prospect inventory, increased the inventory of prospects, and have generally
retained a larger working interest in such prospects. Forest seeks to
maintain a balanced exploration portfolio that includes higher risk
exploration prospects (primarily in the Northwest Territories and Alberta
foothills) that have the potential for large reserves, as well as lower risk
projects (primarily in the Gulf of Mexico). We participate in exploration
activities through selective drilling for our own account, as well as through
farmout arrangements in certain circumstances. In 1998, Forest dedicated
almost 50% of direct exploration and development spending to exploration
activities. In 1999, we have reduced our exploration and development budget
but have still dedicated approximately 40% to exploration activities.
ENHANCE EXISTING PROPERTIES THROUGH AN ACTIVE DEVELOPMENT PROGRAM. We
continually evaluate new imaging, drilling and completion technologies and
their potential application to our existing properties in order to identify
additional development opportunities. We also pursue workovers,
recompletions, secondary recovery operations and other production enhancement
techniques on our properties to increase production.
Our development expenditures and activities on our existing properties
increased in 1998 as compared to prior years. We increased our expenditures
for development from $13.2 million in 1995 to $70.6 million in 1998. We have,
however, reduced our 1999 capital expenditure budget (exploration and
development) due to lower oil and gas prices. We have budgeted net outlays
after property sales of approximately $60 million for 1999, which is less
than our expected cash flow from our producing properties. Approximately 60%
of the 1999 capital expenditures is budgeted for development projects and 40%
for exploration. Approximately two-thirds of budgeted expenditures are
dedicated to U.S. projects and one-third to Canadian projects.
CONTINUE TO PURSUE ATTRACTIVE ACQUISITIONS. We continue to pursue
acquisitions of producing properties. Our selection criteria include (i)
strategic location in a core area of operations or establishment of a new
core area through the acquisition of a significant property base, (ii)
potential for increasing reserves and production through lower risk
exploitation and development, (iii) exploration potential that is consistent
with our objectives, (iv) attractive potential return on investment, and (v)
opportunities for improved operating efficiencies. In Canada, we have an
additional criterion that natural gas properties include sufficient plant
processing capacity and adequate access to markets.
CONTROL OPERATIONS TO MAXIMIZE EFFICIENCIES. We emphasize control of
operations in all of our core operating areas and in our evaluation of
acquisition opportunities. Control of operations positions us to maximize
synergies and operating efficiencies and to control the timing and costs of
drilling operations in order to increase margins and the returns on capital
investments.
CONSERVE CAPITAL RESOURCES. Under the current difficult operating environment
caused by low oil and gas prices, we have reduced budgeted direct exploration
and development spending for 1999 by 40% compared to 1998. By reducing our
planned spending, we plan to improve our liquidity position by using any
excess cash flow from operations to reduce indebtedness.
MAINTAIN FINANCIAL FLEXIBILITY. We are committed to maintaining financial
flexibility, which we believe is important for the successful execution of
our strategy. From January 1, 1995 through December 31, 1998, Forest added a
total of approximately $385 million of common equity through the issuance of
common stock. We seek to reduce our level of debt as a percentage of our
capitalization.
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1998 TRANSACTIONS
In February 1998, Forest purchased interests in oil and gas properties in 13
fields located onshore in Louisiana from a private company for total
consideration of approximately $231 million. The consideration consisted of
approximately $217 million of cash and one million shares of Forest common
stock. The properties had estimated proved reserves of approximately 189 BCFE
at the time of purchase.
In May 1998, we acquired certain oil and gas interests of Unocal Canada
Exploration Limited and Unocal Canada Limited in the Northwest Territories
and frontier areas of Canada. The assets acquired included Unocal's 35%
working interest in the P-66 discovery well on the Flett Prospect in the
southern Northwest Territories, approximately 225,000 net acres of lands in
the Northwest Territories held under exploration licenses on a work permit
basis, certain other working interests and Unocal's data base including
seismic, surface geology, reservoir engineering and other information
collected during Unocal's 40 years of exploration activity in the Northwest
Territories.
In June 1998, we retired our only remaining nonrecourse production payment
loan by issuing to the lender 271,214 shares of common stock valued at
$3,750,000. The loan, which originated in May 1992, had a remaining principal
amount of approximately $14.6 million and a book value of approximately $9.9
million. The loan was secured primarily by certain oil and gas properties in
Oklahoma and the Gulf of Mexico. As a result of the settlement, we recorded
an extraordinary gain of approximately $6.2 million in June 1998.
In June 1998, Forest issued 5.9 million shares of common stock to Anschutz in
exchange for certain oil and gas assets. The oil and gas assets acquired
included an interest in the Anschutz Ranch East Field located in Utah and
Wyoming. Our interest in this field had net proved developed producing
reserves estimated at approximately 72 BCFE at the date of acquisition. We
also acquired all of Anschutz's Canadian oil and gas assets, comprised
primarily of approximately 170,000 net acres of undeveloped land as well as
5.2 BCFE of estimated proved reserves. Our acquisition included certain of
Anschutz's international oil and gas assets comprised of 13 international
projects encompassing approximately 18 million net acres of undeveloped land.
In August 1998, we acquired all of the outstanding common shares of Saxon
Petroleum Inc. not previously owned by us in exchange for approximately 1.1
million shares of Forest common stock. We expect to realize general and
administrative cost savings of approximately $1.5 million (U.S.) per year as
a result of the consolidation of the operations of Saxon with those of our
wholly owned Canadian subsidiary, Canadian Forest Oil Ltd.
Acquisitions have been an important component of our growth strategy, but we
have not made acquisitions simply to increase the size of the company.
Rather, we seek to add assets where there is a long-term market or
unrecognized exploration opportunity. Both the Louisiana and Anschutz
acquisitions in 1998 offer Forest upside potential through both exploration
and development of these fields. The Anschutz acquisition offers development
opportunities at the Anschutz Ranch East Field, as well as exploration
opportunities internationally. Through recompletions and workovers, we expect
to increase production on the Louisiana properties in 1999. In addition, we
have identified numerous exploration opportunities in deeper horizons on
these properties.
SALES AND MARKETS
OIL AND GAS OPERATIONS. Forest's U.S. production is generally sold at the
wellhead to oil and natural gas purchasing companies in the areas where it is
produced. Liquids are typically sold under short-term contracts at prices
based upon posted field prices. Natural gas in the U.S. is generally sold
month to month on the spot market. Currently, nearly all of our U.S. natural
gas is sold at the wellhead at spot market prices. The term "spot market" as
used herein refers to contracts with a term of six months or less or
contracts which call for a redetermination of sales prices every six months
or earlier. We believe that the loss of one or more of our current natural
gas spot purchasers should not have a material adverse effect on Forest's
business in the United States because any individual spot purchaser could be
readily replaced by another spot purchaser who would pay approximately the
same sales price.
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In Canada, liquids are typically sold under short-term contracts at prices
based upon posted field prices. Canadian Forest's natural gas production is
sold primarily through the ProMark Netback Pool which is operated by ProMark,
the marketing subsidiary of Canadian Forest. Canadian Forest sold
approximately 85% of its natural gas production through the ProMark Netback
Pool in 1998.
MARKETING AND TRADING ACTIVITIES. The ProMark Netback Pool matches major end
users with providers of gas supply through arranged transportation channels,
and uses a netback pricing mechanism to establish the wellhead price paid to
producers. Under this netback arrangement, producers receive the blended
market price less related transportation and other direct costs. ProMark
charges a marketing fee for marketing and administering the gas supply pool.
The ProMark Netback Pool gas sales in 1998 averaged 129 MMCF per day, of
which Canadian Forest supplied approximately 35 MMCF per day or 27%.
Approximately 26% of the volumes sold in the ProMark Netback Pool in 1998
were sold at fixed prices. The remainder of the volumes sold were priced in a
variety of ways, including prices based on indices.
In addition to operating the ProMark Netback Pool, ProMark provides two other
marketing services for producers and purchasers of natural gas. ProMark
manages long-term gas supply contracts for its industrial customers by
providing full-service purchasing, accounting and gas nomination services for
these customers on a fee-for-services basis. ProMark also buys and sells gas
in its trading operation for terms as short as one day and as long as one to
two years. Profits generated by trading are derived from the spread between
the prices of gas purchased and sold. ProMark follows procedures to offset
its gas purchase or sales commitments with other gas purchase or sales
contracts, thereby limiting its exposure to price risk. We are, however,
exposed to credit risk in that there exists the possibility that the
counterparties to agreements will fail to perform their contractual
obligations. The credit of counterparties is evaluated and letters of credit
or parent guarantees are obtained when considered necessary to minimize
credit risk.
OTHER FOREIGN OPERATIONS
Forest considers, from time to time, certain oil and gas opportunities in
other foreign countries. Foreign oil and natural gas operations are subject
to certain risks, such as nationalization, confiscation, terrorism,
renegotiation of existing contracts and currency fluctuations. Forest
monitors the political, regulatory and economic developments in any foreign
countries in which it operates.
The assets acquired from Anschutz in 1998 included oil and gas interests in
various foreign countries. The international interests include international
concessions, rights or agreements located in Albania, Austria, Germany,
Italy, Romania, Sicily, South Africa, Spain, Switzerland, Thailand and
Tunisia. Forest intends to further develop prospects and may elect to promote
them out, thereby reducing its working interest while maintaining exposure to
the most attractive opportunities. At this time, we do not anticipate making
any major investments outside of North America. These international interests
comprise approximately 2% of the Company's total assets at December 31, 1998.
COMPETITION
The oil and natural gas industry is intensely competitive. Competition is
particularly intense in the acquisition of prospective oil and natural gas
properties and oil and gas reserves. Forest's competitive position depends on
our geological, geophysical and engineering expertise, our financial
resources, our ability to develop properties and our ability to select,
acquire and develop proved reserves. We compete with a substantial number of
other companies having larger technical staffs and greater financial and
operational resources. Many such companies not only engage in the
acquisition, exploration, development and production of oil and natural gas
reserves, but also carry on refining operations, generate electricity and
market refined products. We also compete with major and independent oil and
gas companies in the marketing and sale of oil and gas to transporters,
distributors and end users. The oil and natural gas industry competes with
other industries supplying energy and fuel to industrial, commercial and
individual consumers. Forest competes with other oil and natural gas
companies in attempting to secure drilling rigs and other
4
equipment necessary for drilling and completion of wells. Such equipment may
be in short supply from time to time. Finally, companies not previously
investing in oil and natural gas may choose to acquire reserves to establish
a firm supply or simply as an investment. Such companies provide competition
for Forest.
Forest's business is affected not only by such competition, but also by
general economic developments, governmental regulations and other factors
that affect our ability to market our oil and natural gas production. The
prices of oil and natural gas realized by Forest are highly volatile. The
price of oil is generally dependent on world supply and demand, while the
price we receive for our natural gas is tied to the specific markets in which
such gas is sold. Declines in crude oil prices or natural gas prices
adversely impact Forest's activities. Our financial position and resources
may also adversely affect our competitive position. Lack of available funds
or financing alternatives will prevent us from executing our operating
strategy and from deriving the expected benefits therefrom. For further
information concerning Forest's financial position, see Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations.
ProMark also faces significant competition from other gas marketers, some of
whom are significantly larger in size and have greater financial resources
than ProMark, Canadian Forest or Forest.
REGULATION
UNITED STATES. Various aspects of the Company's oil and natural gas
operations are regulated by administrative agencies under statutory
provisions of the states where such operations are conducted and by certain
agencies of the Federal government for operations on Federal leases. All of
the jurisdictions in which the Company owns or operates producing crude oil
and natural gas properties have statutory provisions regulating the
exploration for and production of crude oil and natural gas, including
provisions requiring permits for the drilling of wells and maintaining
bonding requirements in order to drill or operate wells and provisions
relating to the location of wells, the method of drilling and casing wells,
the surface use and restoration of properties upon which wells are drilled
and the plugging and abandoning of wells. The Company's operations are also
subject to various conservation laws and regulations. These include the
regulation of the size of drilling and spacing units or proration units and
the number of wells which may be drilled in an area and the unitization or
pooling of crude oil and natural gas properties. In this regard, some states
can order the pooling or integration of tracts to facilitate exploration
while other states rely on voluntary pooling of lands and leases. In
addition, state conservation laws establish maximum rates of production from
crude oil and natural gas wells, generally prohibit the venting or flaring of
natural gas, and impose certain requirements regarding the ratability or fair
apportionment of production from fields and individual wells. Some states,
such as Texas and Oklahoma, have, in recent years, reviewed and substantially
revised methods previously used to make monthly determinations of allowable
rates of production from fields and individual wells. The effect of these
regulations is to limit the amounts of crude oil and natural gas the Company
can produce from its wells, and to limit the number of wells or the location
at which the Company can drill.
The Federal Energy Regulatory Commission (FERC) regulates the transportation
and sale for resale of natural gas in interstate commerce under the Natural
Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978 (NGPA). In the
past, the Federal government has regulated the prices at which oil and gas
could be sold. The Natural Gas Wellhead Decontrol Act of 1989 (the Decontrol
Act) removed all NGA and NGPA price and nonprice controls affecting
producers' wellhead sales of natural gas effective January 1, 1993. While
sales by producers of natural gas, and all sales of crude oil, condensate and
natural gas liquids can currently be made at uncontrolled market prices,
Congress could reenact price controls in the future.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and
636-C (Order No. 636), which require interstate pipelines to provide
transportation separate, or "unbundled", from the pipelines' sales of gas.
Also, Order No. 636 requires pipelines to provide open-access transportation
on a basis that is equal for all gas supplies. Although Order No. 636 does
not directly regulate gas producers like the Company, the FERC has stated
that it intends for Order No. 636 to foster increased competition within all
phases of the natural gas industry. It is unclear what impact, if any,
increased competition within the natural gas industry under Order No. 636
will have on the Company's activities, although recent price declines for
natural gas may, in part, reflect increased competition and
5
more efficient gas transportation resulting from Order No 636. The courts
have largely affirmed the significant features of Order No. 636 and numerous
related orders pertaining to the individual pipelines, although certain
appeals remain pending and the FERC continues to review and modify its open
access regulations. In particular, the FERC has recently begun a broad review
of its transportation regulations, including how they operate in conjunction
with state proposals for retail gas market restructuring, whether to
eliminate cost-of-service rates for short-term transportation, whether to
allocate all short-term capacity on the basis of competitive auctions, and
whether changes to its long-term transportation policies may also be
appropriate to avoid a market bias toward short-term contracts.
While any additional FERC action on these matters would affect the Company
only indirectly, these policy statements and proposed rule changes are
intended to further enhance competition in natural gas markets. The Company
cannot predict what action the FERC will take on these matters, nor can it
predict whether the FERC's actions will achieve its stated goal of increasing
competition in natural gas markets. However, the Company does not believe
that it will be treated materially differently than other natural gas
producers and markets with which it competes.
In Order Nos. 561 and 561-A, the FERC established an indexing system under
which oil pipelines are able to change their transportation rates, subject to
prescribed ceiling levels. The indexing system, which allows or may require
pipelines to make rate changes to track changes in the Producer Price Index
for Finished Goods, minus one percent, became effective January 1, 1995. In
certain circumstances, these rules permit oil pipelines to establish rates
using traditional cost of service or other methods of rate making. The
Company is not able at this time to predict the effects of Order Nos. 561 and
561-A, if any, on the transportation costs associated with oil production
from the Company's oil producing operations.
The Outer Continental Shelf Lands Act (OCSLA) requires that all pipelines
operating on or across the Outer Continental Shelf (the OCS) provide
open-access, non-discriminatory service. To date, the FERC has not issued
rules to implement the OCSLA's requirements on gatherers and other
non-jurisdictional entities, though it has issued such rules for interstate
pipelines. One of the FERC's recently initiated inquiries involves whether it
should alter its regulatory treatment of pipelines and services on the OCS.
The Company cannot predict the outcome of this inquiry, or what, if any,
affect it may have on the Company.
Certain operations the Company conducts are on federal oil and gas leases,
which the Minerals Management Service (MMS) administers. The MMS issues such
leases through competitive bidding. These leases contain relatively
standardized terms and require compliance with detailed MMS regulations and
orders pursuant to the OCSLA (which are subject to change by the MMS). For
offshore operations, lessees must obtain MMS approval for exploration plans
and development and production plans prior to the commencement of such
operations. In addition to permits required from other agencies (such as the
Coast Guard, the Army Corps of Engineers and the Environmental Protection
Agency), lessees must obtain a permit from the MMS prior to the commencement
of drilling. Lessees must also comply with detailed MMS regulations
governing, among other things, engineering and construction specifications
for offshore production facilities, safety procedures, flaring of production,
plugging and abandonment of OCS wells, calculation of royalty payments and
the valuation of production for this purpose and removal of facilities. To
cover the various obligations of lessees on the OCS, the MMS generally
requires that lessees post substantial bonds or other acceptable assurances
that such obligations will be met. The cost of such bonds or other surety can
be substantial and there is no assurance that the Company can continue to
obtain bonds or other surety in all cases. Under certain circumstances, the
MMS may require any Company operations on federal leases to be suspended or
terminated. Any such suspension or termination could materially and adversely
affect the Company's financial condition and operations.
The MMS has under consideration proposals to change the method of calculating
royalties and the valuation of crude oil produced from federal leases. These
changes, if adopted, would modify the valuation procedures for crude oil to
reduce use of oil posted prices and assign a value to crude oil intended to
better reflect market value. The Company cannot predict what action the MMS will
take on this matter, nor can it predict at this stage how the Company might be
affected if the MMS adopts such changes.
6
Additional proposals and proceedings that might affect the oil and gas
industry are regularly considered by Congress, states, the FERC and the
courts. The Company cannot predict when or whether any such proposals may
become effective. In the past, the natural gas industry has been heavily
regulated. There is no assurance that the regulatory approach currently
pursued by the FERC will continue indefinitely. Notwithstanding the
foregoing, the Company does not anticipate that compliance with existing
federal, state and local laws, rules and regulations will have a material or
significantly adverse effect upon the capital expenditures, earnings or
competitive position of the Company or its subsidiaries. No material portion
of Forest's business is subject to renegotiation of profits or termination of
contracts or subcontracts at the election of the Federal government.
OIL SPILL FINANCIAL RESPONSIBILITY REQUIREMENTS - UNITED STATES. As
originally enacted, the Oil Pollution Act of 1990 (OPA) would have required
the Company to establish $150 million in financial responsibility to cover
oil spill related liabilities. Under recent amendments to the OPA, the
responsible person for an offshore facility located seaward of state waters,
including OCS facilities, will be required to provide evidence of financial
responsibility in the amount of $35 million. Although the financial
responsibility requirement for offshore facilities located landward of the
seaward boundary of state waters (including certain facilities in coastal
inland waters) is a lesser amount ($10 million), the Company currently has a
number of offshore facilities located beyond state waters and, thus, is
subject to the $35 million financial responsibility requirement. On August
11, 1998, the MMS promulgated a final rule implementing the financial
responsibility requirements set forth under the OPA amendments. The amount of
financial responsibility may be increased, to a maximum of $150 million, if
the MMS determines that a greater amount is justified based on specific risks
posed by the operations or if the worst case oil-spill discharge volume
possible at the facility may exceed the applicable threshold volumes
specified under the MMS final rule. The Company expects that financial
responsibility could be established through insurance, guaranty, indemnity,
surety bond, letter of credit, qualification as a self insurer or a
combination thereof. The Company cannot predict whether these financial
responsibility requirements under the OPA amendments or the MMS final rule
will result in the imposition of significant additional annual costs to the
Company in the future, but in any event, the impact of the OPA amendments and
the MMS rule is not expected to be any more burdensome to the Company than it
will be to other similarly situated companies involved in oil and gas
exploration and production in the Gulf of Mexico. The Company currently
satisfies similar requirements for its OCS leases under OCSLA.
CANADA. The oil and natural gas industry in Canada is subject to extensive
controls and regulations imposed by various levels of government. It is not
expected that any of these controls or regulations will affect the operations
of the Company in a manner materially different than they would affect other
oil and gas companies of similar size. All current legislation is a matter of
public record and the Company is unable to predict what additional
legislation or amendments may be created.
In Canada, producers of oil negotiate sales contracts directly with oil
purchasers, with the result that the market determines the price of oil. The
price depends in part on oil quality, prices of competing fuels, distance to
market, the value of refined products, and the supply/demand balance. Oil
exports may be made pursuant to export contracts with terms not exceeding one
year in the case of light crude, and not exceeding two years in the case of
heavy crude, provided that an order approving any such export has been
obtained from the National Energy Board (NEB). Any oil export to be made
pursuant to a contract of longer duration (to a maximum of 25 years) requires
an exporter to obtain an export license from the NEB and the issue of such a
license requires the approval of the Governor in Council.
In Canada, the price of natural gas sold in interprovincial and international
trade is determined by negotiation between buyers and sellers. Natural gas
exported from Canada is subject to regulation by the NEB and the Government
of Canada. Exporters are free to negotiate prices and other terms with
purchasers, provided that the export contracts must continue to meet certain
criteria prescribed by the NEB and the Government of Canada. As is the case
with oil, natural gas exports for a term of less than two years or for a term
of 2 to 20 years (in quantities of not more than 30,000 m(3)/day) must be made
pursuant to an NEB order, or, in the case of exports for a longer duration
(to a maximum of 25 years) or a larger quantity, pursuant to an export
license from the NEB with the Governor in Council's approval.
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The provincial governments of Alberta, British Columbia and Saskatchewan also
regulate the volume of natural gas which may be removed from those provinces
for consumption elsewhere based on such factors as reserve availability,
transportation arrangements and market considerations.
On January 1, 1994 the North American Free Trade Agreement (NAFTA) among the
governments of Canada, the United States and Mexico became effective. NAFTA
carries forward most of the material energy terms contained in the
Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada
continues to remain free to determine whether exports to the United States or
Mexico will be allowed provided that any export restrictions do not: (i)
reduce the proportion of energy resource exported relative to domestic use
(based upon the proportion prevailing in the most recent 36-month period),
(ii) impose an export price higher than the domestic price, and (iii) disrupt
normal channels of supply. All three countries are prohibited from imposing
minimum export or import price requirements. NAFTA contemplates clearer
disciplines on regulators to ensure fair implementation of any regulatory
changes and to minimize disruption of contractual arrangements, which is
important for Canadian natural gas exports.
In addition to federal regulation, each province has legislation and
regulations which govern land tenure, royalties, production rates,
environmental protection and other matters. The royalty regime is a
significant factor in the profitability of oil and natural gas production.
Royalties payable on production from lands other than Crown lands are
determined by negotiations between the mineral owner and the lessee. Crown
royalties are determined by government regulation and are generally
calculated as a percentage of the value of the gross production, and the rate
of royalties payable generally depends in part on prescribed reference
prices, well productivity, geographical location, field discovery date and
the type or quality of the petroleum product produced.
From time to time the governments of Canada, Alberta, British Columbia and
Saskatchewan have established incentive programs which have included royalty
rate deductions, royalty holidays and tax credits for the purpose of
encouraging oil and natural gas exploration or enhanced recovery projects.
In Alberta, a producer of oil or natural gas is entitled to a credit against
the royalties payable to the Crown by virtue of the ARTC (Alberta royalty tax
credit) program. The ARTC program is based on a price sensitive formula, and
the ARTC rate varies between 75%, at prices for oil below $100 CDN per cubic
meter, and 25%, at prices above $210 CDN per cubic meter. The ARTC rate is
applied to a maximum of $2 million CDN of Alberta Crown royalties payable for
each producer or associated group of producers. Crown royalties on production
from producing properties acquired from corporations claiming maximum
entitlement to ARTC will generally not be eligible for ARTC. The rate is
established quarterly based on the average "par price", as determined by the
Alberta Department of Energy for the previous quarterly period. Canadian
Forest is eligible for ARTC credits only on eligible properties acquired and
wells drilled after the change of control. On December 22, 1997 the
Government of Alberta gave notice that they intended to review the ARTC
program. Any changes to the program will not take effect prior to 2001.
Oil and natural gas royalty holidays and reductions for specific wells reduce
the amount of Crown royalties paid by the Company to the provincial
governments. In Alberta, the ARTC program provides a rebate on Alberta Crown
royalties paid in respect of eligible producing properties in Alberta.
ENVIRONMENTAL MATTERS. Extensive U.S. federal, state and local laws govern
oil and natural gas operations regulating the discharge of materials into the
environment or otherwise relating to the protection of the environment.
Numerous governmental departments issue rules and regulations to implement
and enforce such laws which are often difficult and costly to comply with and
which carry substantial penalties for failure to comply. Some laws, rules and
regulations relating to protection of the environment may, in certain
circumstances, impose "strict liability" for environmental contamination,
rendering a person liable for environmental and natural resource damages and
cleanup costs without regard to negligence or fault on the part of such
person. Other laws, rules and regulations may restrict the rate of oil and
natural gas production below the rate that would otherwise exist or even
prohibit exploration or production activities in sensitive areas. In
addition, state laws often require some form of remedial action to prevent
8
pollution from former operations, such as closure of inactive pits and
plugging of abandoned wells. The regulatory burden on the oil and natural gas
industry increases its cost of doing business and consequently affects its
profitability. These laws, rules and regulations affect the operations of the
Company. Compliance with environmental requirements generally could have a
material adverse effect upon the capital expenditures, earnings or
competitive position of Forest and its subsidiaries. The Company believes
that it is in substantial compliance with current applicable environmental
laws and regulations and that continued compliance with existing requirements
will not have a material adverse impact on the Company. Nevertheless, changes
in environmental law have the potential to adversely affect the Company's
operations. For instance, a few U.S. courts have ruled that certain wastes
associated with the production of crude oil may be classified as hazardous
substances under the Comprehensive Environmental Response, Compensation, and
Liability Act (commonly called Superfund) and thus the Company could become
subject to the burdensome cleanup and liability standards established under
the federal Superfund program if significant concentrations of such wastes
were determined to be present at the Company's properties or to have been
produced as a result of the Company's operations. Alternately, pending
amendments to Superfund presently under consideration by the U.S. Congress
could relax many of the burdensome cleanup and liability standards
established under the Statute.
The U.S. Oil Pollution Act (OPA) and regulations thereunder impose a variety
of requirements on "responsible parties" related to the prevention of oil
spills and liability for damages resulting from such spills in U.S. waters. A
"responsible party" includes the owner or operator of an onshore facility
pipeline or vessel, or the lessee or permittee of the area in which an
offshore facility is located. OPA assigns liability to each responsible party
for oil cleanup costs and a variety of public and private damages from oil
spills. OPA also requires operators of offshore OCS facilities to demonstrate
to the Minerals Management Service (MMS) that they possess at least $35
million in financial resources that are available to pay for costs that may
be incurred in responding to an oil spill. This financial responsibility
amount can increase up to a maximum of $150 million if the MMS determines
that a greater amount is justified based on specific risks posed by the
operations or if the worst case oil-spill discharge volume possible at a
facility exceeds applicable threshold volumes established by the MMS. While
liability limits apply in some circumstances, a party cannot take advantage
of liability limits if the spill was caused by gross negligence or willful
misconduct or resulted from violation of a federal safety, construction or
operating regulation. If the party fails to report a spill or to cooperate
fully in the cleanup, liability limits likewise do not apply. Even if
applicable, the liability limits for offshore facilities require the
responsible party to pay all removal costs, plus up to $75 million in other
damages. Few defenses exist to the liability imposed by OPA.
The U.S. Water Pollution Control Act (commonly called the Clean Water Act)
imposes restrictions and strict controls regarding the discharge of produced
waters and other oil and gas wastes in navigable waters. Many state discharge
regulations and the federal National Pollutant Discharge Elimination System
generally prohibit the discharge of produced water and sand, drilling fluids,
drill cuttings and certain other substances related to the oil and gas
industry into coastal waters. Although the costs to comply with these zero
discharge mandates under federal or state law may be significant, the entire
industry is expected to experience similar costs in the western Gulf of
Mexico and the Company believes that these costs will not have a material
adverse impact on the Company's financial condition and operations.
In Canada, the oil and natural gas industry is currently subject to
environmental regulation pursuant to provincial and federal legislation.
Environmental legislation provides for restrictions and prohibitions on
releases or emissions of various substances produced or utilized in
association with certain oil and gas industry operations. In addition,
legislation requires that well and facility sites be abandoned and reclaimed
to the satisfaction of provincial authorities. A breach of such legislation
may result in the imposition of fines and penalties.
In Alberta, environmental compliance has been governed by the Alberta
Environmental Protection and Enhancement Act (AEPEA) since September 1, 1993.
In addition to replacing a variety of older statutes which related to
environmental matters, AEPEA also imposes certain new environmental
responsibilities on oil and natural gas operators in Alberta and in certain
instances also imposes greater penalties for violations.
9
British Columbia's Environmental Assessment Act became effective June 30,
1995. This legislation rolls the previous processes for the review of major
energy projects into a single environmental assessment process which
contemplates public participation in the environmental review.
Although the Company maintains insurance against some, but not all, of the
risks described above, including insuring the costs of clean-up operations,
public liability and physical damage, there is no assurance that such
insurance will be adequate to fully cover all such costs or that such
insurance will continue to be available in the future or that such insurance
will be available at premium levels that justify its purchase. The occurrence
of a significant event not fully insured or indemnified against could have a
material adverse effect on the Company's financial condition and operations.
The Company has established guidelines to be followed to comply with U.S. and
Canadian environmental laws, rules and regulations. The Company has
designated a compliance officer whose responsibility is to monitor regulatory
requirements and their impacts on the Company and to implement appropriate
compliance procedures. The Company also employs an environmental manager
whose responsibilities include causing Forest's operations to be carried out
in accordance with applicable environmental guidelines and implementing
adequate safety precautions. Although the Company maintains pollution
insurance against the costs of clean-up operations, public liability and
physical damage, there is no assurance that such insurance will be adequate
to cover all such costs or that such insurance will continue to be available
in the future.
FORWARD-LOOKING STATEMENTS
Certain information in this Form 10-K includes "forward-looking statements"
within the meaning of Section 27A of the Securities Act and Section 21E of
the Securities Exchange Act of 1934, as amended. You can identify these
statements by words such as "may," will," "expect," anticipate," estimate,"
"continue" or other similar words. These statements discuss future
expectations, contain projections of results of operations or financial
condition or state other forward-looking information. When considering such
forward-looking statements, you should keep in mind the risk factors and
other cautionary statements in this Form 10-K. The information disclosed
under "Risk Factors" and other factors noted throughout this Form 10-K,
including certain risks and uncertainties, could cause our actual results to
differ materially from those contained in any forward-looking statement.
Prices for oil and natural gas fluctuate widely and have declined
significantly recently. Numerous uncertainties are inherent in estimating
proved oil and natural gas reserves and in projecting future rates of
production and timing of development expenditures. Many of these
uncertainties are beyond our control. Reserve engineering is a subjective
process of estimating underground accumulations of oil and natural gas that
cannot be measured in an exact way. The accuracy of any reserve estimate
depends on the quality of available data and the interpretation of such data
by geological engineers. As a result, estimates made by different engineers
often vary from one another. In addition, the results of drilling, testing
and production activities may justify revisions of estimates that were made
previously. If significant, such revisions would change the schedule of any
further production and development drilling. Accordingly, reserve estimates
are generally different from the quantities of oil and natural gas that are
ultimately recovered.
RISK FACTORS
IN ADDITION TO THE OTHER INFORMATION SET FORTH ELSEWHERE IN THIS FORM 10-K,
THE FOLLOWING FACTORS SHOULD BE CAREFULLY CONSIDERED WHEN EVALUATING FOREST.
OIL AND GAS PRICE DECLINES AND THEIR VOLATILITY COULD ADVERSELY AFFECT
FOREST'S REVENUES, CASH FLOWS AND PROFITABILITY. Prices for oil and natural
gas fluctuate widely and have declined significantly recently. The average
spot price received by Forest for natural gas produced in the Gulf Coast
decreased from approximately $2.61 per MCF at December 31, 1997 to $2.17 per
MCF at December 31, 1998 and decreased to approximately $1.70 per MCF at
March 1, 1999. During the same period, the NYMEX price for crude oil
decreased from $17.61 per barrel at December 31, 1997 to $12.06 per barrel at
December 31, 1998 and was $12.24 per barrel at March 1, 1999.
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Natural gas prices affect Forest more than oil prices, because most of its
production and reserves are natural gas. At December 31, 1998, 73% of our
estimated proved reserves consisted of natural gas on an MCFE basis and,
during 1998, approximately 71% of our total production consisted of natural
gas.
Forest's revenues, profitability and future rate of growth depend
substantially upon the prevailing prices of oil and natural gas. Prices also
affect the amount of cash flow available for capital expenditures and our
ability to borrow money or raise additional capital. We recently reduced our
1999 capital expenditures budget because of lower oil and gas prices. The
amount we can borrow from banks is subject to redetermination based on
current prices. In addition, we may have ceiling test writedowns when prices
decline. Lower prices may also reduce the amount of oil and natural gas that
Forest can produce economically.
We cannot predict future oil and natural gas prices and prices may decline
further. Factors that can cause this fluctuation include:
- relatively minor changes in the supply of and demand for oil
and natural gas;
- market uncertainty;
- the level of consumer product demand;
- weather conditions;
- domestic and foreign governmental regulations;
- the price and availability of alternative fuels;
- political conditions in the Middle East;
- the foreign supply of oil and natural gas;
- the price of oil and gas imports; and
- overall economic conditions.
We enter into energy swap agreements and other financial arrangements at
various times to attempt to minimize the effect of oil and natural gas price
fluctuations. We cannot assure you that such transactions will reduce risk or
minimize the effect of any decline in oil or natural gas prices. Any
substantial or extended decline in oil or natural gas prices would have a
material adverse effect on our business and financial results. Energy swap
agreements may limit the risk of declines in prices, but such arrangements
may also limit additional revenues from price increases.
For further information concerning prices, market conditions and energy swap
agreements, see Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations and Notes 4, 5, 10 and 11 of Notes to
Consolidated Financial Statements.
ESTIMATES OF OIL AND GAS RESERVES ARE UNCERTAIN AND INHERENTLY IMPRECISE.
This Form 10-K contains estimates of our proved oil and gas reserves and the
estimated future net revenues from such reserves. These estimates are based
upon various assumptions, including assumptions required by the SEC relating
to oil and gas prices, drilling and operating expenses, capital expenditures,
taxes and availability of funds. The process of estimating oil and gas
reserves is complex. This process involves significant decisions and
assumptions in the evaluation of available geological, geophysical,
engineering and economic data for each reservoir. Therefore, these estimates
are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves most likely will vary from those estimated. Any significant variance
could materially affect the estimated quantities and present value of
reserves set forth in this Form 10-K. In addition, we may adjust estimates of
proved reserves to reflect production history, results of exploration and
development, prevailing oil and gas prices and other factors, many of which
are beyond our control.
At December 31, 1998, approximately 16% of our estimated proved reserves were
undeveloped. Recovery of undeveloped reserves requires significant capital
expenditures and successful drilling operations. The reserve data assumes
that we will make significant capital expenditures to develop our reserves.
Although we have prepared
11
estimates of our oil and gas reserves and the costs associated with these
reserves in accordance with industry standards, we cannot assure you that the
estimated costs are accurate, that development will occur as scheduled or
that the results will be as estimated. See Note 14 of Notes to Consolidated
Financial Statements.
You should not assume that the present value of future net revenues referred
to in this Form 10-K is the current market value of our estimated oil and gas
reserves. In accordance with SEC requirements, the estimated discounted
future net cash flows from proved reserves are generally based on prices and
costs as of the date of the estimate. Actual future prices and costs may be
materially higher or lower than the prices and costs as of the date of the
estimate. Recent significant declines in oil and gas prices have reduced
Forest's present value of future net revenues. Any changes in consumption by
gas purchasers or in governmental regulations or taxation will also affect
actual future net cash flows. The timing of both the production and the
expenses from the development and production of oil and gas properties will
affect the timing of actual future net cash flows from proved reserves and
their present value. For example, we have reduced our 1999 capital
expenditure budget. This reduction will delay cash flows and thereby reduce
present value. In addition, the 10% discount factor, which is required by the
SEC to be used in calculating discounted future net cash flows for reporting
purposes, is not necessarily the most accurate discount factor. The effective
interest rate at various times and the risks associated with Forest or the
oil and gas industry in general will affect the accuracy of the 10% discount
factor.
LEVERAGE MATERIALLY AFFECTS OUR OPERATIONS. As of December 31, 1998, our
long-term debt was $505.5 million including $271.9 million outstanding under
our global bank credit facility with a syndicate of banks led by The Chase
Manhattan Bank and The Chase Manhattan Bank of Canada. Our long-term debt
represented 75% of our total capitalization at December 31, 1998.
Our level of debt affects our operations in several important ways, including
the following:
- a large portion of our cash flow from operations is used to pay interest
on borrowings;
- the covenants contained in the agreements governing our debt limit
our ability to borrow additional funds or to dispose of assets;
- the covenants contained in the agreements governing our debt may
affect our flexibility in planning for, and reacting to, changes in
business conditions;
- a high level of debt may impair our ability to obtain additional
financing in the future for working capital, capital expenditures,
acquisitions, general corporate or other purposes; and
- the terms of the agreements governing our debt permit our creditors to
accelerate payments upon an event of default or a change of control.
In addition, we may significantly alter our capitalization in order to make
future acquisitions or develop our properties. These changes in
capitalization may significantly increase our level of debt. A higher level
of debt increases the risk that Forest may default on its debt obligations.
Our ability to meet our debt obligations and to reduce our level of debt
depends on our future performance. General economic conditions and financial,
business and other factors affect our operations and our future performance.
Many of these factors are beyond our control.
If Forest is unable to repay its debt at maturity out of cash on hand, it
could attempt to refinance such debt, or repay such debt with the proceeds of
an equity offering. We cannot assure you that Forest will be able to generate
sufficient cash flow to pay the interest on its debt or that future
borrowings or equity financing will be available to pay or refinance such
debt. In addition, Forest's bank borrowing base is subject to semi-annual
redeterminations. Forest could be forced to repay a portion of its bank
borrowings due to redeterminations of its borrowing base, and we cannot
assure you that we will have sufficient funds to make such repayments. If we
are not able to negotiate renewals of our borrowings or to arrange new
financing, we may have to sell significant assets. Any such sale could have a
material adverse effect on our business and financial results. Factors that
will affect our ability to raise cash through an offering of our capital
stock or a refinancing of our debt include financial market conditions and
our value and performance at the time of such offering or other financing. We
cannot assure you that any such offering or refinancing can be successfully
completed.
12
LOWER OIL AND GAS PRICES INCREASE THE RISK OF CEILING LIMITATION WRITEDOWNS.
We use the full cost method to account for our oil and gas operations.
Accordingly, we capitalize the cost to acquire, explore for and develop oil
and gas properties. Under full cost accounting rules, the net capitalized
costs of oil and gas properties may not exceed a "ceiling limit" which is
based upon the present value of estimated future net cash flows from proved
reserves, discounted at 10%, plus the lower of cost or fair market value of
unproved properties. If net capitalized costs of oil and gas properties
exceed the ceiling limit, we must charge the amount of the excess to
earnings. This is called a "ceiling limitation writedown." This charge does
not impact cash flow from operating activities, but does reduce our
shareholders' equity. The risk that we will be required to write down the
carrying value of oil and gas properties increases when oil and gas prices
are low or volatile. In addition, writedowns may occur if we experience
substantial downward adjustments to our estimated proved reserves or if
purchasers cancel long-term contracts for our natural gas production. In
1998, Forest recorded writedowns of $175 million ($199.5 million pre-tax).
The subsequent significant declines in natural gas prices increase the risk
that we will have a ceiling limitation writedown in the first quarter of
1999. We cannot assure you that we will not experience ceiling limitation
writedowns in the future.
FOREST'S LIQUIDITY IS SUBJECT TO THE RISK OF THE AVAILABILITY OF FINANCING.
We have historically addressed our long-term liquidity needs through the use
of bank credit facilities, the issuance of debt and equity securities and the
use of cash provided by operating activities. We continue to examine the
following alternative sources of long-term capital:
- bank borrowings or the issuance of debt;
- the sale of common stock, preferred stock or other equity securities;
- the issuance of nonrecourse production-based financing or net profits
interests;
- sales of non-strategic properties; o sales of prospects and technical
information; and o joint venture financing.
The availability of these sources of capital will depend upon a number of
factors, some of which are beyond our control. These factors include general
economic and financial market conditions, oil and natural gas prices and the
value and performance of Forest. We may be unable to execute our operating
strategy if we cannot obtain capital from these sources.
FOREST'S ABILITY TO REPLACE PRODUCTION WITH NEW RESERVES IS HIGHLY DEPENDENT
ON ACQUISITIONS OR SUCCESSFUL DEVELOPMENT AND EXPLORATION ACTIVITIES, WHICH
IN TURN ARE ADVERSELY AFFECTED BY FOREST'S REDUCED 1999 CAPITAL EXPENDITURES
BUDGET. In general, the volume of production from oil and gas properties
declines as reserves are depleted. The decline rates depend on reservoir
characteristics. Gulf of Mexico reservoirs experience steep declines, while
the declines in long-lived fields in other regions are relatively slow. A
significant portion of our production is from Gulf of Mexico reservoirs. Our
reserves will decline as they are produced unless we acquire properties with
proved reserves or conduct successful development and exploration activities.
Forest's future natural gas and oil production is highly dependent upon its
level of success in finding or acquiring additional reserves. The business of
exploring for, developing or acquiring reserves is capital intensive and
uncertain. We may be unable to make the necessary capital investment to
maintain or expand our oil and gas reserves if cash flow from operations is
reduced and external sources of capital become limited or unavailable. We
cannot assure you that our future development, acquisition and exploration
activities will result in additional proved reserves or that we will be able
to drill productive wells at acceptable costs.
We have reduced our 1999 capital expenditures budget. It is unlikely,
therefore, that Forest will replace 1999 production based on the lower level
of capital expenditures.
FOREST'S OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF OIL AND GAS DRILLING
AND PRODUCTION ACTIVITIES. Oil and gas drilling and production activities
are subject to numerous risks, many of which are beyond our control. These
risks include the following:
13
- that no commercially productive oil or natural gas reservoirs will be
found;
- that oil and gas drilling and production activities may be shortened,
delayed or canceled; and
- that our ability to develop, produce and market our reserves may be
limited by:
(1) title problems,
(2) weather conditions,
(3) compliance with governmental requirements, and
(4) mechanical difficulties or shortages or delays in the delivery of
drilling rigs, work boats and other equipment.
In the past, we have had difficulty securing drilling equipment in certain of
our core areas. We cannot assure you that the new wells we drill will be
productive or that we will recover all or any portion of our investment.
Drilling for oil and natural gas may be unprofitable. Dry wells and wells
that are productive but do not produce sufficient net revenues after
drilling, operating and other costs are unprofitable. In addition, our
properties may be susceptible to hydrocarbon draining from production by
other operations on adjacent properties.
Our industry also experiences numerous operating risks. These operating risks
include the risk of fire, explosions, blow-outs, pipe failure, abnormally
pressured formations and environmental hazards. Environmental hazards include
oil spills, gas leaks, ruptures or discharges of toxic gases. If any of these
industry operating risks occur, we could have substantial losses. Substantial
losses may be caused by injury or loss of life, severe damage to or
destruction of property, natural resources and equipment, pollution or other
environmental damage, clean-up responsibilities, regulatory investigation and
penalties and suspension of operations. Additionally, a substantial portion
of our oil and gas operations is located in the Gulf of Mexico. The Gulf of
Mexico area experiences tropical weather disturbances, some of which can be
severe enough to cause substantial damage to facilities and possibly
interrupt production. In accordance with industry practice, we maintain
insurance against some, but not all, of the risks described above. We cannot
assure you that our insurance will be adequate to cover losses or
liabilities. Also, we cannot predict the continued availability of insurance
at premium levels that justify its purchase.
FOREST'S CONCENTRATION OF ASSETS INCREASES ITS EXPOSURE TO PRODUCTION
DECLINES. At March 1, 1999, the combined production from six of our offshore
Gulf of Mexico wells represented approximately 28% of Forest's consolidated
daily deliverability. Our production, revenue and cash flow will be adversely
affected if production from these six wells decreases significantly.
THE PROFITABILITY OF FOREST'S GAS MARKETING ACTIVITIES IS SUBJECT TO NUMEROUS
RISKS, INCLUDING CREDIT RISKS AND RESPONSE TO CHANGING CONDITIONS. Our
operations include gas marketing through our subsidiary, ProMark. ProMark's
gas marketing operations consist of the marketing of gas production in
Canada, the purchase and direct sale of third parties' natural gas, the
handling of transportation and operations of third party gas and spot
purchasing and selling of natural gas. The profitability of such natural gas
marketing operations depends on our ability to assess and respond to changing
market conditions, including credit risk. Profitability also depends on our
ability to maximize the volume of third party natural gas that we purchase
and resell and to obtain a satisfactory margin between the purchase price and
the sales price for such volumes. If we are unable to respond accurately to
changing conditions in the gas marketing business, our results of operations
could be materially adversely affected. In addition, ProMark sells a
significant portion of its volumes at fixed prices under long-term contracts.
The loss of one or more such long-term buyers could have a material adverse
effect on Forest. ProMark buys and sells gas in its trading operations for
terms varying from one day to two years. Profits from trading are derived
from the difference between the price of gas purchased and the price of gas
sold. ProMark tries to limit its exposure to price risk by offsetting its gas
purchase or sales commitments with other gas purchase or sales contracts.
However, ProMark is exposed to credit risk because the counterparties to
agreements might not perform their contractual obligation.
FOREST'S INTERNATIONAL OPERATIONS ARE SUBJECT TO THE RISKS OF CURRENCY
FLUCTUATIONS AND IN SOME INSTANCES ECONOMIC AND POLITICAL DEVELOPMENTS. We
have significant operations in Canada. The expenses of such operations are
payable in Canadian dollars while most of the revenue from natural gas and
oil sales is based upon U.S. dollar price indices. As a result, Canadian
operations are subject to the risk of fluctuations in the relative values of
the Canadian
14
and U.S. dollars. Forest is also required to recognize foreign currency
translation gains or losses related to the debt issued by our Canadian
subsidiary because the debt is denominated in U.S. dollars and the functional
currency of such subsidiary is the Canadian dollar. We recently acquired
additional oil and gas assets in other countries. Our foreign operations may
also be adversely affected by local political and economic developments,
royalty and tax increases and other foreign laws or policies, as well as U.S.
policies affecting trade, taxation and investment in other countries.
FOREST OPERATES IN A HIGHLY COMPETITIVE INDUSTRY WHICH MAY ADVERSELY AFFECT
ITS OPERATIONS. We operate in a highly competitive environment. Forest
competes with major and independent oil and gas companies for the acquisition
of desirable oil and gas properties and the equipment and labor required to
develop and operate such properties. Forest also competes with major and
independent oil and gas companies in the marketing and sale of oil and
natural gas. Many of these competitors have financial and other resources
substantially greater than ours.
FOREST'S OPERATIONS ARE SUBJECT TO THE NUMEROUS RISKS OF DRILLING. Drilling
involves numerous risks, including the risk that drilling efforts will not
find commercially productive oil or gas reservoirs. The cost of drilling and
completing wells is often unpredictable, and drilling operations may be
shortened, delayed or canceled as a result of a variety of risks. These risks
include unexpected drilling conditions, pressure or irregularities in
formations, equipment failures or accidents, weather conditions and shortages
or delays in delivery of equipment. We cannot assure you that our future
drilling activities will be successful. Forest's current inventory of seismic
surveys will not necessarily increase the likelihood that it will drill or
complete commercially productive wells. In addition, the volumes of reserves
discovered, if any, would not necessarily be greater than Forest would have
discovered without its current inventory of seismic surveys.
FOREST'S ACQUISITIONS ARE SUBJECT TO THE RISKS OF THE UNCERTAINTIES OF
RECOVERABLE RESERVES AND POTENTIAL LIABILITIES. Our recent growth is due in
part acquisitions of producing properties. The successful acquisition of
producing properties requires an assessment of a number of factors beyond our
control. These factors include recoverable reserves, future oil and gas
prices, operating costs and potential environmental and other liabilities.
Such assessments are inexact and their accuracy is inherently uncertain. In
connection with such assessments, we perform a review of the subject
properties, which we believe is generally consistent with industry practices.
However, such a review will not reveal all existing or potential problems. In
addition, the review will not permit a buyer to become sufficiently familiar
with the properties to fully assess their deficiencies and capabilities. We
do not inspect every platform or well. Even when a platform or well is
inspected, structural and environmental problems are not necessarily
discovered. We are generally not entitled to contractual indemnification for
preclosing liabilities, including environmental liabilities. Normally, we
acquire interests in properties on an "as is" basis with limited remedies for
breaches of representations and warranties. In addition, competition for
producing oil and gas properties is intense and many of our competitors have
financial and other resources which are substantially greater than those
available to us. Therefore, we cannot assure you that we will be able to
acquire oil and gas properties that contain economically recoverable reserves
or that we will acquire such acquisitions at acceptable prices.
THE MARKETABILITY OF FOREST'S PRODUCTION DEPENDS IN PART UPON THE
AVAILABILITY, PROXIMITY AND CAPACITY OF GAS GATHERING SYSTEMS, PIPELINES AND
PROCESSING FACILITIES. U.S. federal and state and Canadian regulation of oil
and gas production and transportation, general economic conditions, and
changes in supply and demand all could adversely affect our ability to
produce and market oil and natural gas. If market factors dramatically
changed, the financial impact on Forest could be substantial. The
availability of markets is beyond our control.
FOREST'S OIL AND GAS OPERATIONS ARE SUBJECT TO VARIOUS U.S. FEDERAL, STATE
AND LOCAL AND CANADIAN FEDERAL AND PROVINCIAL GOVERNMENTAL REGULATION THAT
MATERIALLY AFFECT ITS OPERATIONS. Matters regulated include discharge permits
for drilling operations, drilling and abandonment bonds, reports concerning
operations, the spacing of wells and unitization and pooling of properties
and taxation. At various times, regulatory agencies have imposed price
controls and limitations on production. In order to conserve supplies of oil
and gas, these agencies have restricted the rates of flow of oil and gas
wells below actual production capacity. In addition, the Oil Pollution Act of
1990 requires operators of offshore facilities to prove that they have the
financial responsibility to address potential oil spills. Under such law and
other federal and state environmental statutes, owners and operators of
certain defined facilities are strictly liable for such spills, subject to
certain limitations. A substantial spill from one of our facilities
15
could have a material adverse effect on our results of operations,
competitive position or financial condition. Federal, state, provincial and
local laws regulate production, handling, storage, transportation and
disposal of oil and gas, by-products from oil and gas and other substances
and materials produced or used in connection with oil and gas operations. To
date, our expenditures related to complying with these laws and for
remediation of existing environmental contamination have not been
significant. We believe that we are in substantial compliance with all
applicable laws and regulations. However, the requirements of such laws and
regulations are frequently changed. We cannot predict the ultimate cost of
compliance with these requirements or their effect on our operations.
THE SIGNIFICANT OWNERSHIP POSITION OF ANSCHUTZ COULD LIMIT FOREST'S ABILITY
TO ENTER INTO CERTAIN TRANSACTIONS. As of February 28, 1999, Anschutz owned
approximately 40% of the outstanding shares of our common stock. Pursuant to
a shareholder agreement between Anschutz and Forest, Anschutz may designate
three of Forest's directors. Therefore, Anschutz can substantially influence
matters considered by Forest's Board of Directors. The shareholder agreement
prohibits Anschutz from acquiring in excess of 49.9% of the outstanding
shares of common stock. The shareholder agreement terminates on July 27, 2000.
Under certain circumstances, Anschutz could veto proposed transactions
between Forest and third parties. For example, Anschutz could veto a merger
of Forest, which under applicable law requires the approval of the holders of
two-thirds of the outstanding shares of common stock. Control of Forest most
likely could not be transferred to a third party without Anschutz's consent
and agreement. A third party probably would not offer to pay a premium to
acquire Forest without the prior agreement of Anschutz, even if the Board of
Directors should choose to attempt to sell Forest in the future. In addition,
shareholder approval would be required by New York Stock Exchange rules for
the issuance of common stock to a third party in an amount in excess of 20%
of the outstanding common stock. Anschutz's opposition to such a transaction
could significantly reduce the likelihood of its approval.
16
ITEM 2. PROPERTIES
Forest's principal reserves and producing properties are oil and gas
properties located in the onshore and offshore Gulf of Mexico region, West
Texas, Wyoming and Alberta, Canada.
RESERVES
Information regarding Forest's proved and proved developed oil and gas
reserves and the standardized measure of discounted future net cash flows and
changes therein is included in Note 14 of Notes to Consolidated Financial
Statements.
Since January 1, 1997 Forest has not filed any oil or natural gas reserve
estimates or included any such estimates in reports to any Federal or foreign
governmental authority or agency, other than the Securities and Exchange
Commission (SEC), the MMS and the Department of Energy (DOE). The reserve
estimate report filed with the MMS related solely to Forest's Gulf of Mexico
reserves. There were no differences between the reserve estimates included in
the MMS report, the SEC report, the DOE report and those included herein,
except for production and additions and deletions due to the difference in
the "as of" dates of such reserve estimates.
PRODUCTION
The following table shows net liquids and natural gas production for Forest
and its subsidiaries for the years ended December 31, 1998, 1997 and 1996:
Net Natural Gas and Liquids Production (1)
------------------------------------------
1998 1997 (2) 1996 (2)
------------- ------------- -----------
United States:
Natural Gas (MMCF) 47,394 34,018 28,624
Liquids (MBBLS) 2,405 1,267 1,104
Canada:
Natural Gas (MMCF) 14,916 15,017 13,872
Liquids (MBBLS) 1,864 1,940 1,645
Total (MMCFE) 87,924 68,277 58,990
(1) Volumes reported for natural gas include immaterial amounts of sulfur
production on the basis that one long ton of sulfur is equivalent to 15 MCF
of natural gas. Liquids volumes include both oil and condensate and natural
gas liquids.
(2) Includes amounts delivered pursuant to volumetric production payments. See
Note 5 of Notes to Consolidated Financial Statements.
17
AVERAGE SALES PRICES AND PRODUCTION COSTS PER UNIT OF PRODUCTION
The following table sets forth the average sales prices per MCF of natural
gas and per barrel of liquids and the average production cost per equivalent
unit of production for the years ended December 31, 1998, 1997 and 1996 for
Forest and its subsidiaries:
United States Canada
------------------------------ ------------------------------
1998 1997 1996 1998 1997 1996
--------- --------- -------- --------- ---------- --------
Average Sales Prices:
NATURAL GAS
Total production (MMCF) (1) 47,394 34,018 28,624 14,916 15,017 13,872
Sales price received (per MCF) $ 2.10 2.53 2.36 1.23 1.46 1.41
Effects of energy swaps (per MCF) (2) .09 (.21) (.23) (.02) - (.04)
--------- --------- -------- --------- ---------- --------
Average sales price (per MCF) $ 2.19 2.32 2.13 1.21 1.46 1.37
LIQUIDS:
Oil and condensate:
Total production (MBBLS) 1,919 1,137 964 1,389 1,498 1,308
Sales price received (per BBL) $ 12.16 18.20 20.03 11.95 18.07 20.64
Effects of energy swaps (per BBL) (2) .45 (.23) (1.07) 1.06 (.08) (1.82)
--------- --------- -------- --------- ---------- --------
Average sales price (per BBL) $ 12.61 17.97 18.96 13.01 17.99 18.82
Natural gas liquids:
Total production (MBBLS) 486 130 140 475 442 337
Average sales price (per BBL) $ 7.00 10.62 10.48 7.25 12.42 11.87
Total liquids production (MBBLS) 2,405 1,267 1,104 1,864 1,940 1,645
Average sales price (per BBL) $ 11.48 17.21 17.88 11.54 16.72 17.40
Average production cost (per MCFE) (3) $ .48 .50 .56 .46 .58 .52
(1) Total natural gas production includes scheduled deliveries under volumetric
production payments, net of royalties, of 801 MMCF and 3,168 MMCF 1997 and
1996, respectively. Natural gas delivered pursuant to volumetric production
payment agreements represented approximately 2% and 7% of total natural gas
production 1997 and 1996, respectively. On June 30, 1997 the Company
repurchased its last remaining volumetric production payment. For further
information concerning volumes and prices recorded under volumetric
production payments, see Note 5 of Notes to Consolidated Financial
Statements.
(2) Energy swaps were entered into to hedge the price of spot market volumes
against price fluctuations. Hedged natural gas volumes were 26,527 MMCF,
13,990 MMCF and 12,741 MMCF for the years ended December 31, 1998, 1997 and
1996, respectively. Hedged oil and condensate volumes were 392,900 barrels,
949,000 barrels and 895,600 barrels for 1998, 1997 and 1996, respectively.
The aggregate gains (losses) under energy swap agreements were $6,305,000,
$(7,439,000) and $(10,422,000), respectively, for the years ended December
31, 1998, 1997 and 1996 and were accounted for as increases (reductions) to
oil and gas sales.
(3) Production costs were converted to common units of measure using a
conversion ratio of one barrel of oil to six MCF of natural gas and one
long ton of sulfur to 15 MCF of natural gas. Such production costs exclude
all depreciation, depletion and provision for impairment associated with
property and equipment.
18
PRODUCTIVE WELLS
The following summarizes total gross and net productive wells of Forest and
its subsidiaries at December 31, 1998:
Productive Wells (1)
-------------------------
United States Canada
------------- ------
Gross (2)
Gas 352 358
Oil 70 440
----- -----
Totals (3) 422 798
----- -----
----- -----
Net (4)
Gas 142.5 130.0
Oil 29.2 217.6
----- -----
Totals 171.7 347.6
----- -----
----- -----
(1) Productive wells are producing wells and wells capable of production,
including wells that are shut-in.
(2) A gross well is a well in which a working interest is owned. The number
of gross wells is the total number of wells in which a working interest is
owned.
(3) Includes 23 dual completions in the United States and 17 dual completions
in Canada. Dual completions are counted as one well. If one completion is
an oil completion, the well is classified as an oil well.
(4) A net well is deemed to exist when the sum of fractional ownership working
interests in gross wells equals one. The number of net wells is the sum of
the fractional working interests owned in gross wells expressed as whole
numbers and fractions thereof.
19
DEVELOPED AND UNDEVELOPED ACREAGE
Forest and its subsidiaries held acreage as set forth below at December 31,
1998 and 1997. A majority of the developed acreage is subject to mortgage
liens securing our bank indebtedness. See Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations and Note 4 of Notes
to Consolidated Financial Statements.
Developed Acreage (1) Undeveloped Acreage (2)
--------------------- -----------------------
Gross (3) Net (4) Gross (3) Net (4)
--------- -------- ---------- --------
United States:
Louisiana offshore 117,947 53,498 61,133 42,118
Texas onshore 82,134 31,457 42,195 11,393
Texas offshore 36,742 23,624 52,057 29,004
Oklahoma 26,068 5,052 6,892 2,465
Wyoming 10,217 5,604 90,170 52,379
Other 19,765 9,429 23,963 10,912
------- ------- ---------- ----------
292,873 128,664 276,410 148,271
Canada:
Alberta 261,365 117,853 322,971 189,011
Ontario 10,707 5,354 303,681 151,840
Northwest Territories - - 718,166 350,133
Beaufort Sea - - 384,744 7,248
British Columbia offshore - - 112,308 112,308
Other 39,523 23,615 61,216 32,520
------- ------- ---------- ----------
311,595 146,822 1,903,086 843,060
Other:
South Africa - - 8,100,000 7,290,000
Switzerland - - 3,400,000 3,060,000
Tunisia - - 2,520,420 2,520,420
Germany - - 1,369,775 1,369,775
Albania - - 1,113,185 333,956
Italy - - 1,039,090 917,725
Romania - - 766,900 766,900
Thailand - - 730,675 730,675
------- ------- ---------- ----------
- - 19,040,045 16,989,451
------- ------- ---------- ----------
Total acreage at December 31, 1998 604,468 275,486 21,219,541 17,980,782
------- ------- ---------- ----------
------- ------- ---------- ----------
Total acreage at December 31, 1997 707,710 301,579 1,499,682 523,783
------- ------- ---------- ----------
------- ------- ---------- ----------
(1) Developed acres are those acres which are spaced or assigned to
productive wells.
(2) Undeveloped acres are considered to be those acres on which wells have
not been drilled or completed to a point that would permit the production
of commercial quantities of oil or natural gas, regardless of whether
such acreage contains proved reserves. It should not be confused with
undrilled acreage held by production under the terms of a lease.
(3) A gross acre is an acre in which a working interest is owned. The number
of gross acres is the total number of acres in which a working interest
is owned.
(4) A net acre is deemed to exist when the sum of the fractional ownership
working interests in gross acres equals one. The number of net acres is
the sum of the fractional working interests owned in gross acres
expressed as whole numbers and fractions thereof.
20
During 1998, Forest's gross and net developed acreage decreased approximately
15% and 9%, respectively, as a result of sales of producing properties. Gross
and net undeveloped acreage increased significantly as a result of
international projects acquired in 1998.
Approximately 13% of our net undeveloped acreage at December 31, 1998 is
under leases that have terms expiring in 1999, if not held by production, and
approximately 13% of net undeveloped acreage will expire in 2000 if not also
held by production.
DRILLING ACTIVITY
Forest and its subsidiaries owned interests in gross and net exploratory and
development wells for the years ended December 31, 1998, 1997 and 1996 as set
forth below. This information does not include wells drilled under farmout
agreements.
United States Canada
--------------------- --------------------
1998 1997 1996 1998 1997 1996
Gross Exploratory Wells:
Dry (1) 6 4 4 7 5 4
Productive (2) 7 8 9 2 7 2
---- ---- ---- ---- ---- ----
13 12 13 9 12 6
---- ---- ---- ---- ---- ----
---- ---- ---- ---- ---- ----
Net Exploratory Wells:(3)
Dry (1) 4.3 1.4 2.0 5.6 3.9 2.9
Productive (2) 4.7 4.0 3.5 .7 5.3 1.4
---- ---- ---- ---- ---- ----
9.0 5.4 5.5 6.3 9.2 4.3
---- ---- ---- ---- ---- ----
---- ---- ---- ---- ---- ----
Gross Development Wells:
Dry (1) - 5 3 2 15 4
Productive (2) 9 13 15 14 31 70
---- ---- ---- ---- ---- ----
9 18 18 16 46 74
---- ---- ---- ---- ---- ----
---- ---- ---- ---- ---- ----
Net Development Wells:(3)
Dry (1) - .7 .5 2.0 10.6 .9
Productive (2) 2.6 4.0 1.9 10.0 21.5 19.9
---- ---- ---- ---- ---- ----
2.6 4.7 2.4 12.0 32.1 20.8
---- ---- ---- ---- ---- ----
---- ---- ---- ---- ---- ----
(1) A dry well (hole) is a well found to be incapable of producing either oil
or natural gas in sufficient quantities to justify completion as an oil or
natural gas well.
(2) Productive wells are producing wells and wells capable of production,
including wells that are shut-in.
(3) A net well is deemed to exist when the sum of fractional ownership working
interests in gross wells equals one. The number of net wells is the sum of
the fractional working interests owned in gross wells expressed as whole
numbers and fractions thereof.
21
FARMOUT AGREEMENTS
Under a farmout agreement, outside parties undertake exploration activities
on prospects owned by Forest. This enables us to participate in the
exploration prospects without incurring additional capital costs, although
with a substantially reduced ownership interest in each prospect.
In 1998, seven exploratory wells were drilled in the United States under
farmout agreements. Six were productive and one was a dry hole. In Canada,
two exploratory wells were drilled in 1998 under farmout agreements, both of
which were productive.
PRESENT ACTIVITIES
At December 31, 1998 Forest and its subsidiaries had six exploratory wells
and one development well that were in the process of being drilled. Of the
six exploratory wells, one (in the U.S.) reached total depth and is currently
being evaluated. Of the five remaining exploratory wells (in Canada), three
have been drilled and are being evaluated and the remaining two are still
being drilled. The development well (in the U.S.) is still being drilled.
DELIVERY COMMITMENTS
A significant portion of Canadian Forest's natural gas production is sold
through the ProMark Netback Pool. At December 31, 1998 the ProMark Netback
Pool had entered into fixed price contracts to sell approximately 2.2 BCF of
natural gas in 1999 at an average price of $2.80 CDN per MCF and
approximately 5.4 BCF of natural gas in 2000 at an average price of
approximately $2.24 CDN per MCF. Canadian Forest, as one of the producers in
the ProMark Netback Pool, is obligated to deliver a portion of this gas. In
1998, Canadian Forest supplied 27% of the gas for the Netback Pool.
The Company is obligated to deliver approximately 200 MMCF of natural gas
under existing long-term contracts in the U.S.
22
ITEM 3. LEGAL PROCEEDINGS
The Company, in the ordinary course of business, is a party to various legal
actions. In the opinion of management, none of these actions, either
individually or in the aggregate, will have a material adverse effect on the
Company's financial condition, liquidity or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable.
ITEM 4A. EXECUTIVE OFFICERS OF FOREST
The following information with respect to the executive officers of Forest is
furnished pursuant to Instruction 3 to Item 401(b) of Regulation S-K.
Years with
Name (A) Age Forest Office (B)
- ------------------------ --- ---------- ----------
William L. Dorn* 50 27 Chairman of the Board and Chairman of the
Executive Committee. Chief Executive
Officer until December 1995. Chairman of
the Nominating Committee. Member of the
Board of Directors since 1982.
Robert S. Boswell* 49 13 President since November 1993 and Chief
Executive Officer since December 1995 and
Chief Financial Officer until December 1995.
Member of the Board of Directors since 1986.
Member of the Company's Executive Committee.
Director of C.E. Franklin Ltd.
David H. Keyte 42 11 Executive Vice President and Chief Financial
Officer since November 1997. Vice President
and Chief Financial Officer December 1995.
Vice President and Chief Accounting Officer
from December 1993 until December 1995.
Chairman of the Company's Employee Benefits
Committee.
Forest D. Dorn 44 21 Senior Vice President - Gulf Coast Region
since November 1997. Vice President - Gulf
Coast Region August 1996. Prior thereto Vice
President and General Business Manager from
December 1993 to August 1996. Member of the
Company's Employee Benefits Committee.
23
Years with
Name (A) Age Forest Office (B)
- ------------------------ --- ---------- ----------
Neal A. Stanley 51 2 Senior Vice President - Western Region since
November 1997. Vice President - Western
Region August 1996. Prior thereto President
of Teton Oil and Gas Corporation.
Donald H. Stevens 46 1 Vice President - Capital Markets and Treasurer
since December 1998. Vice President - Capital
Markets and Strategic Initiatives August 1997.
Prior thereto Vice President - Corporate Relations
and Capital Markets of Barrett Resources Corporation.
Joan C. Sonnen 45 9 Corporate Secretary since March 1999 and
Controller since December 1993. Member of the
Company's Employee Benefits Committee.
- -------------------
*Also a Director
(A) William L. Dorn and Forest D. Dorn are brothers.
(B) The term of office of each officer is one year from the date of his or her
election immediately following the last annual meeting of shareholders and
until the officer's respective successor has been elected and qualified or
until his or her earlier death, resignation or removal from office
whichever occurs first. Each of the named persons has held the office
indicated since the last annual meeting of shareholders, except as
otherwise indicated.
24
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
COMMON STOCK
Forest Oil Corporation has one class of common equity securities outstanding,
its Common Stock, par value $.10 per share (Common Stock).
On February 28, 1999, the Company's 44,647,295 shares of Common Stock were
held by 1,559 holders of record.
Forest's Common Stock was listed on the New York Stock Exchange on November
18, 1997; prior thereto it was traded on the Nasdaq National Market. The high
and low intraday sales prices of the Common Stock for each quarterly period
of the years presented are listed in the chart below. There were no dividends
declared on the Common Stock in 1997, 1998, or in the first quarter of 1999.
High Low
---- ---
1997: First Quarter $ 19-3/8 $ 12-7/8
Second Quarter 15-3/8 12-1/4
Third Quarter 18-1/2 13-1/4
Fourth Quarter 19 13-3/16
1998: First Quarter $ 17-3/8 $ 13
Second Quarter 16-1/4 13-1/4
Third Quarter 14-3/4 8
Fourth Quarter 11-3/4 7-9/16
1999: First Quarter (through March 10) $ 8-15/16 $ 5-3/8
DIVIDEND RESTRICTIONS
The restrictions on Forest's present or future ability to pay dividends are
(i) the provisions of the New York Business Corporation Law (NYBCL), (ii)
certain restrictive provisions in the Indentures executed in connection with
Canadian Forest's 8 3/4% Senior Subordinated Notes due September 15, 2007
which are guaranteed by Forest and Forest's 10 1/2% Senior Subordinated Notes
due 2006, and (iii) the Fourth Amended and Restated Credit Agreement dated
March 4, 1999 with The Chase Manhattan Bank, as agent for a group of banks,
under which Forest is restricted in amounts it may pay as dividends (other
than dividends payable in Common Stock). Under these dividends restrictions,
Forest was not prohibited from paying cash dividends on its Common Stock as
of March 10, 1999.
Forest has not paid dividends on its Common Stock during the past five years
and does not anticipate that it will do so in the foreseeable future. The
future payment of dividends, if any, on the Common Stock is within the
discretion of the Board of Directors and will depend on Forest's earnings,
capital requirements, financial condition and other relevant factors. There
is no assurance that Forest will pay any dividends. For further information
regarding the Company's equity securities and its ability to pay dividends on
its Common Stock, see Notes 4, 7 and 8 of Notes to Consolidated Financial
Statements.
25
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
The following table sets forth selected financial and operating data of
Forest on a historical basis as of and for each of the years in the five-year
period ended December 31, 1998. This data should be read in conjunction with
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations and the Consolidated Financial Statements and Notes
thereto.
Years Ended December 31,
------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(In Thousands Except Per Share Amounts)
FINANCIAL DATA
Revenue:
Marketing and processing $ 151,079 184,399 187,374 - -
Oil and gas sales 170,740 155,242 128,713 82,275 114,541
---------- ------- ------- ------ -------
Total revenue $ 321,819 339,641 316,087 82,275 114,541
Earnings (loss) before cumulative effect of change
in accounting principle and extraordinary items $ (197,786) 3,089 1,139 (17,996) (67,853)
Net earnings (loss) $ (191,590) (9,270) 3,305 (17,996) (81,843)
Weighted average number of common shares outstanding 40,910 33,669 25,062 7,360 5,619
Net earnings (loss) attributable to common stock $ (191,590) (9,459) 1,147 (20,156) (84,004)
Basic earnings (loss) per share:
Earnings (loss) attributable to common stock
before cumulative effect of change in
accounting principle and extraordinary items $ (4.83) .09 (.04) (2.74) (12.46)
Cumulative effect of change in accounting
principle - - - - (2.49)
Extraordinary items .15 (.37) .09 - -
---------- ------- ------- ------ -------
Net earnings (loss) attributable to common stock $ (4.68) (.28) .05 (2.74) (14.95)
Diluted earnings (loss) per share:
Earnings (loss) attributable to common
stock before cumulative effect of change in
accounting principle and extraordinary items $ (4.83) .08 (.04) (2.74) (12.46)
Cumulative effect of change in accounting principle - - - - (2.49)
Extraordinary items .15 (.35) .09 - -
---------- ------- ------- ------ -------
Net earnings (loss) attributable to common stock $ (4.68) (.27) .05 (2.74) (14.95)
Total assets $ 759,736 647,782 563,458 321,043 324,832
Long-term debt $ 505,450 254,760 168,859 193,879 207,054
Other long-term liabilities $ 24,267 51,787 53,560 27,139 28,166
Deferred revenue $ - - 7,591 15,137 35,908
Shareholders' equity $ 168,991 261,827 242,443 44,297 6,086
26
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA (CONTINUED)
Years Ended December 31,
------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(In Thousands Except per Share Amounts and Volumes)
OPERATING DATA
Annual production: (1)
Gas (MMCF) 62,310 49,035 42,496 33,342 48,048
Liquids (MBBLS) 4,269 3,207 2,749 1,173 1,543
Average price received:
Gas (per MCF) (2) $ 1.95 2.06 1.89 1.77 1.90
Liquids (per Barrel) $ 11.51 16.92 17.59 15.86 14.83
Capital expenditures, net of asset sales 461,452 147,130 234,556 44,913 29,839
Proved Reserves: (3)
Gas (MMCF) 564,264 378,315 334,180 231,890 231,638
Liquids (MBBLS) 35,069 24,636 24,014 10,467 7,313
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves (3) $ 522,831 439,570 559,869 256,917 207,549
- -------------------
(1) Includes amounts attributable to required deliveries under volumetric
production payments. See Note 5 of Notes to Consolidated Financial
Statements.
(2) Amounts shown for 1995 exclude the effects of a gas contract settlement.
Including such amount, the average sales price for 1995 was $1.90 per MCF.
(3) The 1998, 1997, 1996 and 1995 amounts include 100% of the reserves owned by
Saxon, a consolidated subsidiary in which the Company held a majority
interest in 1997, 1996 and 1995, but which is a wholly owned subsidiary as
of December 31, 1998.
27
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis should be read in conjunction with
Forest's Consolidated Financial Statements and Notes thereto.
RESULTS OF OPERATIONS
The net loss for 1998 was $191,590,000 compared to a net loss of $9,270,000
in 1997. The 1998 period included a writedown of oil and gas properties of
$175,000,000, net of related deferred taxes ($199,500,000 pre-tax), an
extraordinary gain on extinguishment of debt of $6,196,000 and a noncash loss
on currency translation of $8,320,000 related to subordinated debt issued by
Canadian Forest. The 1997 period included an extraordinary loss on
extinguishment of debt of $12,359,000, as well as a noncash loss on currency
translation of $4,051,000. Exclusive of these items, the net loss would have
been $14,466,000 in 1998 compared to net income of $7,140,000 in 1997. Higher
production volumes in 1998 were more than offset by lower natural gas and
liquids sales prices and higher interest and depletion expense.
The net loss for 1997 was $9,270,000 compared to net earnings of $3,305,000
in 1996. Earnings for the 1996 period include an extraordinary gain on
extinguishment of debt of $2,166,000. Exclusive of the 1997 items mentioned
above and the 1996 extraordinary gain on extinguishment of debt, net income
would have been $7,140,000 in 1997 and $1,139,000 in 1996. The improvement in
1997 was attributable primarily to higher natural gas prices and increased
production from successful drilling programs in 1996 and 1997.
Marketing and processing revenue decreased by 18% to $151,079,000 in 1998
from $184,399,000 in 1997 and the related marketing and processing expense
decreased by 18% to $144,758,000 in 1998 from $175,847,000 in the previous
year. The gross margin for marketing and processing activities decreased 26%
to $6,321,000 in 1998 from $8,552,000 in 1997. The decrease resulted from
lower volumes processed and a decrease in product prices. Marketing and
processing revenue decreased by 2% to $184,399,000 in 1997 from $187,374,000
in 1996 and the related marketing and processing expense decreased by 2% to
$175,847,000 in 1997 from $178,706,000 in the previous year. The gross margin
reported for marketing and processing activities was $8,552,000 in 1997 which
is comparable to $8,668,000 reported in 1996.
Oil and gas sales revenue increased by 10% to $170,740,000 in 1998 from
$155,242,000 in 1997. Revenue from higher production volumes was partially
offset by lower prices received for both oil and natural gas. Production
volumes for natural gas in 1998 increased 27% from 1997. Production volumes
for liquids (consisting of oil, condensate and natural gas liquids) were 33%
higher in 1998 than in 1997. The increases in 1998 are due to Gulf of Mexico
discoveries and volumes attributable to producing properties acquired in
1998. The average sales price received for natural gas in 1998 decreased 5%
compared to the average sales price received in 1997. The average sales price
received for liquids production in 1998 decreased 32% compared to the average
sales price received during 1997.
Oil and gas sales revenue increased by 21% to $155,242,000 in 1997 from
$128,713,000 in 1996. Production volumes for natural gas in 1997 increased
15% from 1996 due primarily to discoveries in the Gulf of Mexico being
brought onto production. Production volumes for liquids were 17% higher in
1997 than in 1996 due primarily to new production from Gulf of Mexico and
Canadian properties. The average sales price received for natural gas in 1997
increased 9% compared to the average sales price received in 1996. The
average sales price received by Forest for its liquids production during 1997
decreased 4% compared to the average sales price received during 1996.
Oil and gas production expense of $41,983,000 in 1998 increased 16% from
$36,284,000 in 1997. The 1998 period includes additional production expense
related to acquired properties. On an MCFE basis, production expense
decreased 9% to $.48 per MCFE in 1998 compared to $.53 in 1997. The decrease
is due primarily to lower per-unit costs related to certain 1998 property
acquisitions as well as offshore fixed costs being spread over a larger
28
production base. The decrease was partially offset by the effects of
significant expensed workovers in the Onshore Gulf Coast Region.
Oil and gas production expense of $36,284,000 in 1997 increased 13% from
$32,199,000 in 1996 due primarily to expenses relating to new production from
Gulf of Mexico properties, temporary transportation expenses associated with
the Bigoray field in Alberta and the inclusion of twelve months of costs for
Canadian Forest in 1997 versus only eleven months in 1996. On an MCFE basis,
production expense was $.53 per MCFE in 1997 compared to $.55 in 1996.
The production volumes, weighted average sales prices and production expenses
for the years ended December 31, 1998, 1997 and 1996 for Forest and its
subsidiaries were as follows:
Year Ended December 31, 1998
-----------------------------------------------------------------
Gulf Coast Region
------------------- Western Total Total
Offshore Onshore Region U.S. Canada Company
-------- ------- ------- ----- ------ -------
NATURAL GAS
Total production (MMCF) 26,521 12,883 7,990 47,394 14,916 62,310