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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, 1997
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: 0-4597
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 $360,638,000 as of February 27, 1998 (based
on the last reported sale price of such stock on the New York Stock Exchange
Composite Tape).
There were 37,320,228 shares of the registrant's Common Stock, Par Value
$.10 Per Share outstanding as of February 27, 1998.
Document incorporated by reference: Proxy Statement of Forest Oil
Corporation relative to the Annual Meeting of Shareholders to be held in May
1998, which is incorporated into Part III of this Form 10- K.
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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 24
Item 4A. Executive Officers of Forest 24
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters 26
Item 6. Selected Financial and Operating Data 28
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 30
Item 8. Financial Statements and Supplementary Data 43
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 43
PART III
Item 10. Directors and Executive Officers of the Registrant 87
Item 11. Executive Compensation 87
Item 12. Security Ownership of Certain Beneficial Owners and Management 87
Item 13. Certain Relationships and Related Transactions 87
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 87
PART I
ITEM 1. BUSINESS
THE COMPANY
Forest Oil Corporation and its subsidiaries (Forest or the Company) are
engaged in the acquisition, exploration, development, production and
marketing of natural gas and crude oil in North America. The Company was
incorporated in New York in 1924, the successor to a company formed in 1916,
and has been a publicly held company since 1969. The Company is active in
several of the major exploration and producing areas in and offshore the
United States and in Canada.
Forest's principal reserves and producing properties are located in the
onshore and offshore Gulf of Mexico region, West Texas, Wyoming and Alberta,
Canada. Approximately 56% of the Company's oil and gas reserves are in the
United States and 44% are in Canada. Approximately 61% of total 1997
production was in the United States and approximately 39% was in Canada. The
Company currently operates 39 offshore platforms in the Gulf of Mexico, and
1997 production from this area accounted for approximately 47% of the
Company's reported 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 6 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.)
The Company 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, 1997 Forest had 267 employees,
of whom 202 were salaried and 65 were hourly. Of the salaried employees, 17
are dedicated to the Company's marketing and processing business. For
financial information relating to the Company's industry segments, see Note
16 of Notes to Consolidated Financial Statements.
OPERATING STRATEGY
The Company's strategy is to focus on exploration, exploitation, development
and acquisition of oil and gas producing properties located in selected areas
in North America where the Company has expertise and experience. The Company
will pursue this strategy through the following initiatives:
EXPAND EXPLORATION. The Company is expanding exploration as a source of
future growth, particularly opportunities that benefit from the selective use
of advanced technologies such as new 3-D seismic processing techniques and
production and completion methods. The Company is also seeking to apply
proven technologies to deeper water prospects in the Gulf of Mexico and to
prospects in the Northwest Territories in Canada. Since improving its
capitalization, the Company has accelerated the exploration and development
of its inventory of prospects and generally retained a larger working
interest in such prospects. In addition, the Company has continued to acquire
additional prospects identified by the Company's exploration teams. The
Company seeks to maintain a balanced exploration portfolio that includes
higher risk exploration prospects that have the potential for larger
reserves, as well as lower risk projects. The Company participates in
exploration activities through selective drilling for its own account, as
well as through farmout arrangements in certain circumstances. In 1997,
Forest dedicated $65,438,000 or 42% of its capital expenditures budget to
exploration activities. In 1997, a total of 12 exploratory wells were
drilled in the United States and Canada, resulting in eight producing wells
and four dry holes. Also in 1997, under farmout agreements, six exploratory
wells were drilled, resulting in three producing wells and three dry holes.
In 1998, Forest has dedicated approximately $57,700,000 or 43% of its capital
expenditures budget to exploration activities.
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INCREASE EXPLOITATION AND DEVELOPMENT OF EXISTING PROPERTIES. The Company
continually evaluates new imaging, drilling and completion technologies and
their potential application to the Company's existing properties in order to
identify additional exploitation and development opportunities. The Company
increased exploitation and development expenditures and activities on its
existing properties in 1997 as compared to prior years. The Company also
pursues workovers, recompletions, secondary recovery operations and other
production enhancement techniques on its properties to increase production.
CONTINUE TO PURSUE ACQUISITIONS. The Company continues to pursue
acquisitions of producing properties that meet selection criteria that
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, (iv) attractive
potential return on investment, and (v) opportunities for improved operating
efficiencies. In Canada, Forest has an additional criterion that natural gas
properties include sufficient plant processing capacity and adequate access
to markets.
On February 3, 1998 the Company purchased 13 oil and gas properties located
onshore Louisiana (the Louisiana properties) for total consideration of
approximately $231,000,000 (the Louisiana Acquisition). The consideration
consisted of approximately $217,000,000 in cash, funded primarily from the
Company's bank credit facility and from the issuance by Canadian Forest Oil
Ltd. (Canadian Forest) of $75,000,000 principal amount of 8 3/4% Senior
Subordinated Notes due 2007 (the 8 3/4% Notes), and 1,000,000 shares of the
Company's common stock. Estimated proved reserves acquired in the Louisiana
Acquisition were approximately 186 BCFE at an average property acquisition
cost of $1.24 per MCFE.
The Company has an agreement in principle with Anschutz whereby the Company
will issue to Anschutz 5,950,000 shares of the Company's common stock in
exchange for certain oil and gas assets (the Anschutz Transaction). The
consummation of the Anschutz Transaction is subject to the completion of a
definitive agreement and the approval of the transaction by the Company's
shareholders, other than Anschutz, at the Company's annual shareholders'
meeting in May, 1998. The oil and gas assets include Anschutz's interest in
the Anschutz Ranch East Field, certain Canadian properties and other
international projects. There are approximately 80 BCFE of estimated proved
reserves associated with the Anschutz Transaction.
During 1997, the Company's acquisitions totaled 10.4 BCFE of estimated proved
reserves at an average property acquisition cost of $.81 per MCFE.
On January 31, 1996 Forest acquired ATCOR Resources Ltd. for approximately
$136,000,000, including acquisition costs of approximately $1,000,000. This
company, which has been renamed Canadian Forest Oil Ltd. (Canadian Forest),
is a Canadian corporation engaged in oil and gas exploration, production and
processing in western Canada. Estimated proved reserves acquired in the
Canadian Forest transaction were approximately 151 BCFE at an average
property acquisition cost of $.85 per MCFE ($.60 per MCFE net of related
deferred taxes). As part of the ATCOR acquisition, Forest separated ATCOR's
natural gas marketing operation from its exploration and production business
and renamed the marketing business Producers Marketing Ltd. (ProMark). In
addition to marketing Canadian Forest's own gas production, ProMark provides
a full range of gas marketing and management services to outside parties.
Other acquisitions by the Company during 1996 totaled 33 BCFE at an average
property acquisition cost of $.69 per MCFE.
During 1995, the Company's acquisitions totaled 44.0 BCFE at an average
property acquisition cost of $.61 per MCFE. These amounts represent
primarily the reserves of Saxon Petroleum Inc. (Saxon), a consolidated
subsidiary of the Company in which the Company purchased a majority interest
on December 20, 1995. Saxon is an Alberta, Canada corporation engaged in oil
and gas exploration and production primarily in western Canada.
The Company had estimated proved reserves of 711 BCFE at December 31, 1997 on
a pro forma basis giving effect to the Louisiana Acquisition, of which
approximately 69% were natural gas reserves. This represents an increase of
48% compared to estimated proved reserves of 481 BCFE at December 31, 1996 of
which approximately 70% was
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natural gas. The Anschutz Transaction, if consummated, will increase the
Company's estimated pro forma proved reserves to 791 BCFE, and will decrease
the percentage which are natural gas reserves to approximately 67%.
MAINTAIN FINANCIAL FLEXIBILITY. The Company is committed to maintaining
financial flexibility, which management believes is important for the
successful execution of its operating strategy. The Company substantially
reduced its debt as a percent of book capitalization from 98% as of December
31, 1994 to 48% as of December 31, 1997. From 1995 through December 1997,
the Company added a total of approximately $300,000,000 of common equity. As
a result of the Louisiana Acquisition, the Company's debt as a percentage of
book capitalization increased to approximately 62% on a pro forma basis as
of December 31, 1997. Successful completion of the proposed Anschutz
Transaction would decrease this percentage to approximately 53%. Management
seeks to continue to reduce the Company's level of debt as a percentage of
its capitalization.
SALES AND MARKETS
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. Crude oil and
condensate are typically sold under short-term contracts at prices which are
based upon posted field prices. Natural gas in the U.S. is generally sold
month to month on the spot market. For the month of March 1998, nearly all
(99.7%) of the Company's U.S. natural gas was 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. The Company believes that the loss
of one or more of its current natural gas spot purchasers should not have a
material adverse effect on the Company'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.
In Canada, crude oil and condensate are typically sold under short-term
contracts at prices which are based upon posted field prices. Canadian
Forest's natural gas production is sold primarily through the ProMark Netback
Pool which is operated by the Company's subsidiary ProMark. The 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. Canadian Forest sold approximately 85% of its natural gas
production through the ProMark Netback Pool in 1997.
The ProMark Netback Pool gas sales in 1997 averaged 128 MMCF per day, of
which Canadian Forest supplied approximately 35 MMCF per day or 27%.
Approximately 17% of the volumes sold in the ProMark Netback Pool in 1997
were sold at fixed prices under one year or longer contracts. The remainder
of the volumes sold in the ProMark Netback Pool are priced in a variety of
ways, including prices based on indices. The loss of one or more of such
long-term buyers could have a material adverse effect on ProMark and Canadian
Forest.
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. The Company is,
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 to minimize credit risks.
For information concerning sales to major customers, see Note 13 of Notes to
Consolidated Financial Statements.
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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 proposed Anschutz Transaction contemplates the acquisition by Forest of
oil and gas interests in various foreign countries. The international
interests include thirteen international concessions, rights or agreements
held by or under negotiation with Anschutz. The interests that the Company
would acquire are 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. The international interests comprise approximately
1% of the Company's total assets on a pro forma basis at December 31, 1997.
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 its geological, geophysical and engineering expertise, on its financial
resources, its ability to develop its properties and its ability to select,
acquire and develop proved reserves. Forest competes 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. The Company also competes with major and
independent oil and gas companies in the marketing and sale of oil and gas to
transporters, distributors and end users. There is also competition between
the oil and natural gas industry and other industries supplying energy and
fuel to industrial, commercial and individual consumers. Forest also
competes with other oil and natural gas companies in attempting to secure
drilling rigs and other 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 will also 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 its ability to market its 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 Forest receives for its 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. The Company's financial position and
resources may also adversely affect the Company's competitive position. Lack
of available funds or financing alternatives will prevent the Company from
executing its operating strategy and from deriving the expected benefits
therefrom. For further information concerning the Company'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 the Company.
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 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
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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 density of wells which may be drilled and the unitization or pooling of
crude oil and natural gas properties. In this regard, some states allow the
forced 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 of production. 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 pursuant to 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. 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. Deregulation of wellhead sales in the natural gas industry began
with the enactment of the NGPA in 1978. In 1989, Congress enacted the
Natural Gas Wellhead Decontrol Act (the Decontrol Act). The Decontrol Act
removed all NGA and NGPA price and nonprice controls affecting wellhead sales
of natural gas effective January 1, 1993.
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 the Company's activities, 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 Order No. 636 could provide the Company
with additional market access and more fairly applied transportation service
rates, Order No. 636 could also subject the Company to more restrictive
pipeline imbalance tolerances and greater penalties for violation of those
tolerances. Order 636 and subsequent FERC orders issued in individual
pipeline restructuring proceedings have been the subject of appeals, the
results of which have generally supported the FERC's open-access policy. In
1996, the United States Court of Appeals for the District of Columbia Circuit
largely upheld Order No. 636. Because further review of certain of these
orders is still possible, other appeals remain pending and the FERC continues
to review and modify its open access regulations, it is difficult to predict
the ultimate impact of the orders on the Company and its production efforts.
The FERC has announced several important transportation-related policy
statements and proposed rule changes, including the appropriate manner in
which interstate pipelines release capacity under Order No. 636 and, more
recently, the price which shippers can charge for their released capacity.
In addition, in 1995, FERC issued a policy statement on how interstate
natural gas pipelines can recover the costs of new pipeline facilities. In
January 1996, the FERC issued a policy statement and a request for comments
concerning alternatives to its traditional cost-of-service ratemaking
methodology. A number of pipelines have obtained FERC authorization to
charge negotiated rates as one such alternative. In February 1997, the FERC
announced a broad inquiry into issues facing the natural gas industry to
assist the FERC in establishing regulatory goals and priorities in the
post-Order No. 636 environment. In November 1997, the FERC issued a proposed
rulemaking to further standardize pipeline transportation tariffs that, if
implemented as proposed, could adversely affect the reliability of scheduled
interruptible transportation service. In December 1997, the FERC requested
comments on the financial outlook of the natural gas pipeline industry,
including among other matters, whether the FERC's current rate making
policies are suitable in the current industry environment. 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
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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.
Commencing in October 1993, the FERC issued a series of rules (Order Nos. 561
and 561-A) establishing 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. Although the FERC has opted not to
impose the regulations of Order No. 509, in which the FERC implemented the
OCSLA, on gatherers and other non-jurisdictional entities, the FERC has
retained the authority to exercise jurisdiction over those entities if
necessary to permit non-discriminatory access to service or the OCS.
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. The MMS has promulgated regulations requiring offshore
production facilities located on the OCS to meet stringent engineering and
construction specifications. The MMS proposed additional safety-related
regulations concerning the design and operating procedures for OCS production
platforms and pipelines. These proposed regulations were withdrawn pending
further discussions among interested federal agencies. The MMS also has
regulations restricting the flaring or venting of natural gas and has
recently proposed to amend such regulations to prohibit the flaring of liquid
hydrocarbons and oil without prior authorization. Similarly, the MMS has
promulgated other regulations governing the plugging and abandonment of wells
located offshore and the removal of all production 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.
In addition, the MMS is conducting an inquiry into certain contract
agreements from which producers on MMS leases have received settlement
proceeds that are royalty bearing and the extent to which producers have paid
the appropriate royalties on those proceeds. The Company believes that this
inquiry will not have a material impact on its financial condition, liquidity
or results of operations.
In April 1997, after two years of study, the MMS withdrew proposed changes to
the way it values natural gas for royalty payments. These proposed changes
would have established an alternative market-based method to calculate
royalties on certain natural gas sold to affiliates or pursuant to non-arm's
length sales contracts.
The MMS has also issued a notice of proposed rulemaking in which it proposes
to amend its regulations governing the calculation of royalties and the
valuation of crude oil produced from federal leases. This proposed rule
would modify the valuation procedures for both arm's length and non-arm's
length crude oil transactions to decrease reliance on oil posted prices and
assign a value to crude oil that better reflects market value, establish a
new MMS form for collecting value differential data, and amend the valuation
procedure for the sale of federal royalty oil. The
6
Company cannot predict what action the MMS will take on this matter, nor can
it predict at this stage of the rulemaking proceeding how the Company might
be affected by this amendment to the MMS' regulations.
Recently, the MMS has issued a final rule to clarify the types of costs that
are deductible transportation costs for purposes of royalty valuation of
production sold off the lease. In particular, under the rule, the MMS will
not allow deduction of costs associated with marketer fees, cash out and
other pipeline imbalance penalties, or long-term storage fees. The Company
cannot predict what, if any, effect the new rule will have on its operations.
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. 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. 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 the final form of any
financial responsibility rule that may be adopted by the MMS under OPA, but
in any event, the impact of the 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. 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.
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 and the value of refined products. 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 (up 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 Canadian federal government.
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. Producers and 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
must be made pursuant to an NEB order, or, in the case of exports for a
longer duration, pursuant to an export license from the NEB with Canadian
federal government approval.
7
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 $2,000,000 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. The ARTC program provides a rebate on Crown royalties paid in
respect of eligible producing properties in Alberta.
ENVIRONMENTAL MATTERS. Extensive federal, state, provincial 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 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
pollution from former operations, such as closure of inactive pits and
plugging of abandoned wells. The regulatory burden on the
8
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 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 a facility 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. OPA also requires
operators of offshore 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. 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 recently enacted zero discharge mandates under federal or state
law may be significant, the entire industry is expected to experience similar
costs 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.
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
9
be adequate to 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
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 of the statements set forth under "Item 1. - Business" and "Item 2.
- -Properties" and "Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations" and elsewhere in this Form 10-K, include
"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 (the Exchange Act). All statements, other than statements of
historical facts included in this Form 10-K, regarding planned capital
expenditures, the availability of capital resources to fund capital
expenditures, estimates of proved reserves, the number of anticipated wells
to be drilled, the Company's financial position, business strategy and other
plans and objectives for future operations, are forward-looking statements.
Although the Company believes that the expectations reflected in such
forward-looking statements are reasonable, it can give no assurance that such
expectations will prove to have been correct. There are numerous
uncertainties inherent in estimating quantities of proved oil and natural gas
reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of the
Company. Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in
an exact way, and the accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation
and judgment. As a result, estimates made by different engineers often vary
from one another. In addition, results of drilling, testing and production
subsequent to the date of an estimate may justify revisions of such estimate
and such revisions, if significant, 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. Additional important factors that could cause actual
results to differ materially from the Company's expectations are disclosed
under "Risk Factors" and elsewhere in this Form 10-K. All subsequent written
and oral forward-looking statements attributable to the Company or persons
acting on its behalf are expressly qualified in their entirety by such
factors.
RISK FACTORS
IN ADDITION TO THE OTHER INFORMATION SET FORTH ELSEWHERE IN THIS FORM 10-K,
THE FOLLOWING FACTORS RELATING TO THE COMPANY SHOULD BE CAREFULLY CONSIDERED
WHEN EVALUATING THE COMPANY.
VOLATILITY OF OIL AND NATURAL GAS PRICES. The Company's revenues,
profitability and future rate of growth are substantially dependent upon the
prevailing prices of, and demand for, oil and natural gas. Prices for oil
and natural gas are subject to wide fluctuation in response to relatively
minor changes in the supply of and demand for oil and natural gas, market
uncertainty and a variety of additional factors that are beyond the control
of the Company. These factors include 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. From time to time, oil and gas
prices have been depressed by excess domestic and imported supplies. There
can be no assurance that current price levels will be sustained. It is
impossible to predict future oil and natural gas price movements with any
certainty. Declines in oil and natural gas prices will adversely affect the
Company's financial condition, liquidity
10
and results of operations and may reduce the amount of the Company's oil and
natural gas that can be produced economically.
The Company is impacted more by natural gas prices than by oil prices,
because the majority of its production and reserves are natural gas. At
December 31, 1997, 72% of the Company's estimated proved reserves consisted
of natural gas on an MCFE basis and, during 1997, 72% of the Company's total
production consisted of natural gas. The average spot price received by the
Company for natural gas produced in the Gulf Coast decreased from $3.89 per
MCF at December 31, 1996 to approximately $2.61 per MCF at December 31, 1997
and is expected to average approximately $2.26 per MCF for the month of March
1998. During the same periods, the West Texas Intermediate price for crude
oil decreased from $23.75 per barrel to $14.75 per barrel and was $12.25 per
barrel at March 1, 1998.
In order to attempt to minimize the product price volatility to which the
Company is subject, the Company, from time to time, enters into energy swap
agreements and other financial arrangements with third parties to attempt to
reduce the Company's short-term exposure to fluctuations in future oil and
natural gas prices. There can be no assurance, however, that such hedging
transactions will reduce risk or mitigate the effect of any substantial or
extended decline in oil or natural gas prices. Any substantial or extended
decline in the prices of oil or natural gas would have a material adverse
effect on the Company's financial condition, liquidity and results of
operation. For further information concerning market conditions, long-term
contracts, production payments and energy swap agreements, see Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations and Notes 5, 6, 11 and 12 of Notes to Consolidated Financial
Statements.
UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES. This Form 10-K contains
estimates of the Company's proved oil and gas reserves and the estimated
future net revenues therefrom that rely upon various assumptions, including
assumptions required by the Securities and Exchange Commission (the
Commission) as 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, requiring significant decisions
and assumptions in the evaluation of available geological, geophysical,
engineering and economic data for each reservoir. As a result, such
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 may vary substantially from
those estimated. Any significant variance in these assumptions could
materially affect the estimated quantities and present value of reserves set
forth in this Form 10-K. In addition, the Company's proved reserves may be
subject to downward or upward revision based upon production history, results
of future exploration and development, prevailing oil and gas prices and
other factors, many of which are beyond the Company's control. Actual
production, revenues, taxes, development expenditures and operating expenses
with respect to the Company's reserves will likely vary from the estimates
used, and such variances may be material.
Approximately 22% of the Company's total estimated proved reserves at
December 31, 1997 were undeveloped, and thus are by their nature less
certain. Recovery of such reserves will require significant capital
expenditures and successful drilling operations. The reserve data assumes
that substantial capital expenditures by the Company will be required to
develop such reserves. Although costs and reserves estimates attributable to
the Company's oil and gas reserves have been prepared in accordance with
industry standards, no assurance can be given that the estimated costs are
accurate, that development will occur as scheduled or that the results will
be as estimated. See Note 17 of Notes to Consolidated Financial Statements.
The present value of future net revenues referred to in this Form 10-K should
not be construed as the current market value of the estimated oil and gas
reserves attributable to the Company's properties. In accordance with
applicable requirements of the Commission, the estimated discounted future
net cash flows from proved reserves are generally based on prices and costs
as of the date of the estimate, whereas actual future prices and costs may be
materially higher or lower. The recent significant declines in oil and gas
prices would have the effect of reducing the Company's present value of
future net revenues. See "Volatility of Oil and Natural Gas Prices." Actual
future net cash flows will also be affected by increases or decreases in
consumption by gas purchasers and changes in governmental regulations or
taxation. The timing of actual future net cash flows from proved reserves,
and thus their actual present value, will be affected by the timing of both
the production and the incurrence of expenses in
11
connection with development and production of oil and gas properties. In
addition, the 10% discount factor, which is required by the Commission to be
used in calculating discounted future net cash flows for reporting purposes,
is not necessarily the most appropriate discount factor based on interest
rates in effect from time to time and risks associated with the Company or
the oil and gas industry in general.
EFFECTS OF LEVERAGE. As of December 31, 1997, the Company's long-term debt
was $254,760,000 including $85,550,000 outstanding under its bank credit
facility (the Global Credit Facility). In connection with the consummation
of the Louisiana Acquisition, the Company increased its aggregate borrowing
capacity under the Global Credit Facility from $130,000,000 to $260,000,000.
As of February 28, 1998, the Company had outstanding aggregate borrowings of
$224,900,000 under the Global Credit Facility. See Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations and
Note 5 of Notes to Consolidated Financial Statements.
The Company's level of indebtedness will have several important effects on
its operations, including (i) a substantial portion of the Company's cash
flow from operations will be dedicated to the payment of interest on its
indebtedness and will not be available for other purposes, (ii) the covenants
contained in the Global Credit Facility and 8 3/4% Notes Indenture limit its
ability to borrow additional funds or to dispose of such assets and may
affect the Company's flexibility in planning for, and reacting to, changes in
business conditions, (iii) the Company's ability to obtain additional
financing in the future for working capital, capital expenditures,
acquisitions, general corporate purposes or other purposes may be impaired,
and (iv) the terms of certain of the Company's indebtedness permit its
creditors to accelerate payments upon certain events of default or a change
of control of the Company. Moreover, future acquisition or development
activities may require the Company to alter its capitalization significantly.
These changes in capitalization may significantly alter the leverage of the
Company. The Company's ability to meet its debt service obligations and to
reduce its total indebtedness will be dependent upon the Company's future
performance, which will be subject to general economic conditions and to
financial, business and other factors affecting the operations of the
Company, many of which are beyond its control. There can be no assurance
that the Company's future performance will not be adversely affected by such
economic conditions and financial, business and other factors or that the
Company will be able to meet its debt service obligations. See Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources.
Furthermore, to the extent that the Company is unable to repay its
indebtedness at maturity out of cash on hand, it could attempt to refinance
such indebtedness, or repay such indebtedness with the proceeds of an equity
offering, at or prior to their maturity. There can be no assurance that the
Company will be able to generate sufficient cash flow to service its interest
payment obligations under its indebtedness or that future borrowings or
equity financing will be available for the payment or refinancing of the
Company's indebtedness. To the extent that the Company is not successful in
negotiating renewals of its borrowings or in arranging new financing, it may
have to sell significant assets which would have a material adverse effect on
the Company's business and results of operations. Among the factors that
will affect the Company's ability to effect an offering of its capital stock
or refinance its indebtedness are financial market conditions and the value
and performance of the Company at the time of such offering or refinancing.
There can be no assurance that any such offering or refinancing can be
successfully completed. Any failure by the Company to satisfy its obligations
with respect to any of its indebtedness at maturity or prior thereto would
constitute a default under agreements governing other indebtedness, if any,
of the Company. Such defaults could result in a default on the 8 3/4% Notes
and could delay or preclude payment of interest or principal thereon. See
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations - Liquidity and Capital Resources.
CEILING LIMITATION WRITEDOWNS. The Company reports its operations using the
full cost method of accounting for oil and gas properties. The Company
capitalizes 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, the Company is subject to a ceiling limitation writedown to
the extent of such excess. A ceiling limitation writedown is a charge to
earnings which does not impact cash flow from operating activities. However,
such writedowns impact the amount of the Company's shareholders' equity. The
risk that the Company
12
will be required to write down the carrying value of its oil and gas
properties increases when oil and gas prices are depressed or volatile. In
addition, writedowns may occur if the Company has substantial downward
revisions in its estimated proved reserves or if purchasers abrogate
long-term contracts for its natural gas production. The recent significant
declines in oil and gas prices increase the risk that the Company may be
required to record a ceiling limitation writedown. See "Volatility of Oil and
Natural Gas Prices." No assurance can be given that the Company will not
experience ceiling limitation writedowns in the future. See Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
AVAILABILITY OF FINANCING. The Company has historically addressed its
long-term liquidity needs through the issuance of debt and equity securities
when market conditions permit, and through the use of credit facilities and
cash provided by operating activities. The Company continues to examine
alternative sources of long-term capital, including bank borrowings or the
issuance of debt instruments, the sale of common stock, preferred stock or
other equity securities of the Company, the issuance of nonrecourse
production-based financing or net profits interests, sales of non-strategic
properties, prospects and technical information, or joint venture financing.
Availability of these sources of capital and, therefore, the Company's
ability to execute its operating strategy will depend upon a number of
factors, including general economic and financial market conditions, oil and
natural gas prices and the value and performance of the Company, some of
which are beyond the control of the Company.
REPLACEMENT OF RESERVES. In general, the volume of production from oil and
gas properties declines as reserves are depleted. The decline rates depend
on reservoir characteristics and vary from the steep declines characteristic
of Gulf of Mexico reservoirs, where the Company has a significant portion of
its production, to the relatively slow declines characteristic of long-lived
fields in other regions. Except to the extent the Company acquires
properties containing proved reserves or conducts successful development and
exploration activities, or both, the proved reserves of the Company will
decline as reserves are produced. The Company's future natural gas and oil
production is, therefore, 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. To the extent cash
flow from operations is reduced and external sources of capital become
limited or unavailable, the Company's ability to make the necessary capital
investment to maintain or expand its asset base of oil and gas reserves would
be impaired. In addition, there can be no assurance that the Company's
future development, acquisition and exploration activities will result in
additional proved reserves or that the Company will be able to drill
productive wells at acceptable costs.
INDUSTRY RISKS. Oil and gas drilling and production activities are subject
to numerous risks, many of which are beyond the Company's control. These
risks include the risk that no commercially productive oil or natural gas
reservoirs will be encountered, that operations may be curtailed, delayed or
canceled and that title problems, weather conditions, compliance with
governmental requirements, mechanical difficulties or shortages or delays in
the delivery of drilling rigs, work boats and other equipment may limit the
Company's ability to develop, produce and market its reserves. The Company
has encountered particular difficulties in securing drilling equipment in
certain of its core areas in the past 12 months. There can be no assurance
that new wells drilled by the Company will be productive or that the Company
will recover all or any portion of its investment. Drilling for oil and
natural gas may involve unprofitable efforts, not only from dry wells but
also from wells that are productive but do not produce sufficient net
revenues to return a profit after drilling, operating and other costs. In
addition, the Company's properties may be susceptible to hydrocarbon drainage
from production by other operators on adjacent properties.
Industry operating risks include the risk of fire, explosions, blow-outs,
pipe failure, abnormally pressured formations and environmental hazards such
as oil spills, gas leaks, ruptures or discharges of toxic gases, the
occurrence of any of which could result in substantial losses to the Company
due to 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 the
Company's oil and gas operations are located in the Gulf of Mexico, an area
that is subject to tropical weather disturbances, some of which can be severe
enough to cause substantial damage to facilities and possibly interrupt
production. In accordance with customary industry practice, the Company
maintains insurance against some, but not all, of the risks described above.
There can be no assurance that any insurance will be adequate to
13
cover losses or liabilities. The Company cannot predict the continued
availability of insurance at premium levels that justify its purchase.
CONCENTRATION OF ASSETS. At March 1, 1998, the Company had four offshore
Gulf of Mexico wells, the combined production from which represented
approximately 17% of the Company's daily deliverability. The Company's
production, revenue and cash flow could be adversely affected if production
from these properties decreases to a significant degree.
GAS MARKETING - TRADING AND CREDIT RISK. The Company's operations include
gas marketing through its subsidiary, ProMark. ProMark's gas marketing
operations consist of the marketing of Canadian Forest's gas production, 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 in large part on the ability of the Company to assess and
respond to changing market conditions, including credit risk. Profitability
of such natural gas marketing operations also depends in large part on the
ability of the Company to maximize the volume of third party natural gas
which the Company purchases and resells and on the ability of the Company to
obtain a satisfactory margin between the purchase price and the sales price
for such volumes. The inability of the Company to respond appropriately to
changing conditions in the gas marketing business could materially adversely
affect the Company's results of operations. In addition, a significant
portion of the volumes sold by ProMark are sold at fixed prices under
long-term contracts. The loss of one or more such long term buyers could
have a material adverse effect on the Company. ProMark buys and sells gas in
its trading operations 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 endeavors to offset its gas
purchase or sales commitments with other gas purchase or sales contracts,
thereby limiting its exposure to price risk. The Company is, however,
exposed to credit risk in that there exists the possibility that the
counterparties to agreements will fail to perform their contractual
obligations.
INTERNATIONAL OPERATIONS. A substantial portion of the Company's operations
is located in Canada. The expenses of such operations are payable in
Canadian dollars and most of the revenue derived from natural gas and oil
sales is based upon U.S. dollar price indices. As a result, the Company's
Canadian operations are subject to the risk of fluctuations in the relative
value of the Canadian and U.S. dollar. The Company is also required to
recognize foreign currency translation gains or losses related to its 8 3/4%
Notes issued by Canadian Forest because the debt is denominated in U.S.
dollars and the functional currency of Canadian Forest is the Canadian
dollar. As a result of the decline in the value of the Canadian dollar
relative to the U.S. dollar during the fourth quarter of 1997, the Company
reported a noncash translation loss of approximately $4,051,000. The
Company's Canadian operations may also be adversely affected by Canadian
local political and economic developments, royalty and tax increases and
other Canadian laws or policies, as well as U.S. policies affecting trade,
taxation and investment in Canada. To the extent that the Company pursues
opportunities in other countries, similar risks will apply.
COMPETITION. The Company operates in a highly competitive environment. The
Company competes with major and independent oil and gas companies for the
acquisition of desirable oil and gas properties, as well as the equipment and
labor required to develop and operate such properties. The Company also
competes with major and independent oil and gas companies in the marketing
and sale of oil and natural gas to marketers and end-users. Many of these
competitors have financial and other resources substantially greater than
those of the Company.
DRILLING RISKS. Drilling involves numerous risks, including the risk that no
commercially productive oil or gas reservoirs will be encountered. The cost
of drilling and completing wells is often unpredictable, and drilling
operations may be curtailed, delayed or cancelled as a result of a variety of
factors, including unexpected drilling conditions, pressure or irregularities
in formations, equipment failures or accidents, weather conditions and
shortages or delays in delivery of equipment. There can be no assurance as
to the success of the Company's future drilling activities. The Company's
current inventory of 2-D and 3-D seismic surveys will not necessarily
increase the likelihood that the Company will drill or complete commercially
productive wells or that the volumes of reserves discovered, if any, would
necessarily be greater than the Company would have discovered without its
current inventory of seismic surveys.
14
ACQUISITION RISKS. The Company's recent growth has been attributable in part
to acquisitions of producing properties. The successful acquisition of
producing properties requires an assessment of recoverable reserves, future
oil and gas prices, operating costs, potential environmental and other
liabilities and other factors beyond the Company's control. Such assessments
are necessarily inexact and their accuracy inherently uncertain. In
connection with such an assessment, the Company performs a review of the
subject properties that it believes to be generally consistent with industry
practices. Such a review, however, will not reveal all existing or potential
problems nor will it permit a buyer to become sufficiently familiar with the
properties to fully assess their deficiencies and capabilities. Inspections
may not always be performed on every platform or well, and structural and
environmental problems are not necessarily observable even when an inspection
is undertaken. The Company is generally not entitled to contractual
indemnification for preclosing liabilities, including environmental
liabilities, and generally acquires interests in the 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 the Company's competitors have financial and other resources which
are substantially greater than those available to the Company. Therefore, no
assurance can be given that the Company will be able to acquire producing oil
and gas properties which contain economically recoverable reserves or that it
will make such acquisitions at acceptable prices.
UNCERTAINTIES OF CONSUMMATION OF THE ANSCHUTZ TRANSACTION. The Company has
an agreement in principle with Anschutz to acquire certain oil and gas assets
from Anschutz. The consummation of the Anschutz Transaction is subject to the
completion of a definitive agreement and the approval of the Company's
shareholders, other than Anschutz at the Company's annual shareholders'
meeting in May, 1998. There can be no assurance that conditions to the
Anschutz Transaction will be met or that the transactions will be completed
according to the terms currently contemplated, if at all.
MARKETABILITY OF OIL AND GAS PRODUCTION. The marketability of the Company's
production depends in part upon the availability, proximity and capacity of
gas gathering systems, pipelines and processing facilities. U.S. federal and
state regulation and Canadian regulation of oil and gas production and
transportation, general economic conditions, and changes in supply and demand
all could adversely affect the Company's ability to produce and market its
oil and natural gas. If market factors were to change dramatically, the
financial impact on the Company could be substantial. The availability of
markets is beyond the control of the Company and thus represents a
significant risk.
GOVERNMENT REGULATION. The Company's oil and gas operations are subject to
various U.S. federal, state and local and Canadian federal and provincial
governmental regulations. Matters subject to regulation 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. From time to time, regulatory agencies have imposed
price controls and limitations on production by restricting the rate of flow
of oil and gas wells below actual production capacity in order to conserve
supplies of oil and gas. In addition, the Oil Pollution Act of 1990 (OPA)
requires operators of offshore facilities to establish evidence of financial
responsibility to address potential oil spills. OPA, together with other
federal and state environmental statutes, also imposes strict liability on
owners and operators of certain defined facilities for such spills, subject
to certain limitations. A substantial spill from one of the Company's
facilities could have a material adverse effect on the Company's results of
operations, competitive position or financial condition. The production,
handling, storage, transportation and disposal of oil and gas, by-products
thereof and other substances and materials produced or used in connection
with oil and gas operations are also subject to regulation under federal,
state, provincial and local laws and regulations primarily relating to the
protection of human health and the environment. To date, expenditures
related to complying with these laws and for remediation of existing
environmental contamination have not been significant in relation to the
results of operations of the Company. Although the Company believes it is in
substantial compliance with all applicable laws and regulations, the
requirements imposed by such laws and regulations are frequently changed and
subject to interpretation, and the Company is unable to predict the ultimate
cost of compliance with these requirements or their effect on its operations.
See Item 1. Regulation.
OWNERSHIP POSITION OF ANSCHUTZ. Based on the number of shares outstanding on
February 27, 1998, Anschutz owned approximately 29.8% of the outstanding shares
of Forest's common stock. The Company has agreed in principle to issue
5,950,000 shares of common stock to Anschutz in the Anschutz Transaction,
which would increase Anschutz's ownership position to approximately 39.5%.
Pursuant to a shareholders agreement between Anschutz and the Company (the
Anschutz Agreement), Anschutz may designate three of the Company's 11
directors.
15
Therefore, Anschutz has the ability to exert substantial influence with
respect to matters considered by the Company's Board of Directors. The
Anschutz Agreement prohibits Anschutz from acquiring in excess of 40% of the
outstanding shares of common stock. The Anschutz Agreement terminates on
July 27, 2000. Under certain circumstances Anschutz could have a veto power
over proposed transactions between the Company and third parties such as a
merger, which, under applicable law, requires the approval of the holders of
two-thirds of the outstanding shares of common stock. It is unlikely that
control of the Company could be transferred to a third party without
Anschutz's consent and agreement. It is also unlikely that a third party
would offer to pay a premium to acquire the Company without the prior
agreement of Anschutz, even if the Board of Directors should choose to
attempt to sell the Company in the future.
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
Historical and pro forma information regarding the Company'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 17
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, 1997, 1996 and 1995:
Net Natural Gas and Liquids Production (1)(2)
---------------------------------------------
1997 1996 1995
------ ------ ------
United States:
Natural Gas (MMCF) 34,018 28,624 33,342
Liquids (MBBLS) 1,267 1,104 1,173
Canada:
Natural Gas (MMCF) 15,017 13,872 -
Liquids (MBBLS) 1,940 1,645 -
TOTAL (MMCFE) 68,277 58,990 40,380
(1) Includes amounts delivered pursuant to volumetric production payments. See
Note 6 of Notes to Consolidated Financial Statements.
(2) 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.
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, 1997, 1996 and 1995 for
Forest and its subsidiaries:
UNITED STATES CANADA
------------------------ ---------------
1997 1996 1995 1997 1996
------ ------ ------ ------ ------
Average Sales Prices:
NATURAL GAS
Total production (MMCF) (1) 34,018 28,624 33,342 15,017 13,872
Sales price received (per MCF) (2) $ 2.53 2.36 1.65 1.46 1.41
Effects of energy swaps (per MCF) (3) (.21) (.23) .12 - (.04)
------- ------ ------ ------ ------
Average sales price (per MCF) (2) $ 2.32 2.13 1.77 1.46 1.37
LIQUIDS:
Oil and Condensate:
Total production (MBBLS) (4) 1,137 964 1,121 1,498 1,308
Sales price received (per BBL) $ 18.20 20.03 16.36 18.07 20.64
Effects of energy swaps (per BBL) (3) (.23) (1.07) (.50) (.08) (1.82)
------- ------ ------ ------ ------
Average sales price (per BBL) $ 17.97 18.96 15.86 17.99 18.82
Natural gas liquids:
Total production (MBBLS) 130 140 52 442 337
Average sales price (per BBL) $ 10.62 10.48 15.81 12.42 11.87
Total liquids production (MBBLS) 1,267 1,104 1,173 1,940 1,645
Average sales price (per BBL) $ 17.21 17.88 15.86 16.72 17.40
Average production cost (per MCFE) (5) $ .50 .56 .56 .58 .52
(1) Total natural gas production includes scheduled deliveries under
volumetric production payments, net of royalties, of 801 MMCF, 3,168 MMCF
and 9,120 MMCF in 1997 and 1996 and 1995, respectively. Natural gas
delivered pursuant to volumetric production payment agreements represented
approximately 2%, 7% and 27% of total natural gas production in 1997, 1996
and 1995, 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 Notes 6 and 13 of Notes to Consolidated Financial Statements.
(2) Amounts shown for 1995 exclude the effects of a gas contract settlement.
Including such amount, the sales price received and average sales price for
natural gas in 1995 were $1.78 and $1.90 per MCF, respectively. For
further information regarding the gas contract settlement, see Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations and Note 14 of Notes to Consolidated Financial Statements.
(3) Energy swaps were entered into to hedge the price of spot market volumes
against price fluctuations. Hedged natural gas volumes were 13,990 MMCF,
12,741 MMCF and 10,146 MMCF for the years ended December 31, 1997, 1996 and
1995, respectively. Hedged oil and condensate volumes were 949,000
barrels, 895,600 barrels and 498,000 barrels for 1997, 1996 and 1995,
respectively. The aggregate gains (losses) under energy swap agreements
were $(7,439,000), $(10,422,000) and $3,536,000, respectively, for the
years ended December 31, 1997, 1996 and 1995 and were accounted for as
increases (reductions) to oil and gas sales.
(4) An immaterial amount of oil production was covered by scheduled deliveries
under volumetric production payments in 1996 and 1995.
(5) 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 the Company
and its subsidiaries at December 31, 1997:
Productive Wells (1)
------------------------
United States Canada
------------- ------
Gross (2)
Gas 271 373
Oil 164 505
---- -----
Totals (3) 435 878
---- -----
Net (4)
Gas 79.1 134.5
Oil 99.5 235.1
---- -----
Totals 178.6 369.6
---- -----
---- -----
(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 25 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,
1997 and 1996 and on a pro forma basis including acreage from the Louisiana
Acquisition at December 31, 1997. A majority of the developed acreage is
subject to mortgage liens securing either the bank indebtedness or
nonrecourse secured debt of the Company and its subsidiaries. See Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations and Note 5 of Notes to Consolidated Financial Statements.
Developed Acreage (1) Undeveloped Acreage (2)
--------------------- -----------------------
Gross (3) Net (4) Gross (3) Net (4)
--------- ------- --------- -------
United States:
Louisiana offshore 106,846 43,567 84,003 60,425
Oklahoma 40,326 13,604 23,926 5,469
Texas onshore 103,348 47,423 16,220 7,537
Texas offshore 39,622 26,114 48,980 40,327
Wyoming 8,161 4,066 53,995 22,782
Other 14,367 3,415 17,605 6,646
------- ------- --------- -------
312,670 138,189 244,729 143,186
Canada
Alberta 355,238 140,665 278,516 157,684
Northwest Territories - - 917,474 188,374
Other 39,802 22,725 58,963 34,539
------- ------- --------- -------
395,040 163,390 1,254,953 380,597
------- ------- --------- -------
Total acreage at December 31, 1997 707,710 301,579 1,499,682 523,783
------- ------- --------- -------
------- ------- --------- -------
Total acreage at December 31, 1996 797,797 333,136 910,031 252,585
------- ------- --------- -------
------- ------- --------- -------
Pro forma acreage at December 31,
1997 (5) 721,239 309,724 1,503,064 525,819
------- ------- --------- -------
------- ------- --------- -------
(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.
(5) Includes acreage acquired in the Louisiana Acquisition, all of which is
onshore Louisiana.
During 1997, the Company's historical gross and net developed acreage decreased
approximately 11% and 9%, respectively, due primarily to property sales and
abandonment of wells. Historical gross and net undeveloped acreage increased
approximately 13% and 37%, respectively, due primarily to acquisition of new
acreage, net of expirations.
Approximately 7% of the Company's total historical net undeveloped acreage at
December 31, 1997 is under leases that have terms expiring in 1998, if not held
by production, and approximately 17% of net undeveloped acreage will expire in
1999 if not also held by production.
20
DRILLING ACTIVITY
Forest and its subsidiaries owned interests in gross and net exploratory and
development wells for the years ended December 31, 1997, 1996 and 1995 as set
forth below. This information does not include wells drilled under farmout
agreements nor does it include any wells drilled with respect to properties
included in the Louisiana Acquisition.
United States Canada
------------------- ------------
1997 1996 1995 1997 1996
---- ---- ---- ---- ----
Gross Exploratory Wells:
Dry (1) 4 4 3 5 4
Productive (2) 8 9 1 7 2
--- --- -- ---- ----
12 13 4 12 6
--- --- -- ---- ----
--- --- -- ---- ----
Net Exploratory Wells:(3)
Dry (1) 1.4 2.0 1.3 3.9 2.9
Productive (2) 4.0 3.5 .3 5.3 1.4
--- --- -- ---- ----
5.4 5.5 1.6 9.2 4.3
--- --- -- ---- ----
--- --- -- ---- ----
Gross Development Wells:
Dry (1) 5 3 - 15 4
Productive (2) 13 15 6 31 70
--- --- -- ---- ----
18 18 6 46 74
--- --- -- ---- ----
--- --- -- ---- ----
Net Development Wells:(3)
Dry (1) .7 .5 - 10.6 .9
Productive (2) 4.0 1.9 .6 21.5 19.9
--- --- -- ---- ----
4.7 2.4 .6 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.
FARMOUT AGREEMENTS
Under a farmout agreement, outside parties undertake exploration activities
using prospects owned by Forest. This enables the Company to participate in the
exploration prospects without incurring additional capital costs, although with
a substantially reduced ownership interest in each prospect.
In 1997, three exploratory wells were drilled in the United States under farmout
agreements. Two were productive and one was a dry hole. In Canada, eight
development wells and three exploratory wells were drilled in 1997 under farmout
agreements. Six of the development wells were productive and two were dry
holes. One of the exploratory wells was productive and two were dry holes.
21
PRESENT ACTIVITIES
At December 31, 1997 Forest and its subsidiaries had three exploratory and four
development wells that were in the process of being drilled. One of the
exploratory wells (in Canada) was a dry hole and the other two (both in Canada)
are still being drilled. Three of the development wells (two in the U.S. and
one in Canada) were determined to be productive in 1998 and the fourth (in the
U.S.) is still being drilled. Four additional wells (two exploratory and two
development) were being drilled under farmout agreements. One of the
exploratory wells (in the U.S.) was determined to be productive in 1998 and the
second (in Canada) is still being drilled. One of the development wells (in the
U.S.) was determined to be productive in 1998 and the second (in Canada) is
still being drilled.
DELIVERY COMMITMENTS
The Company is obligated to deliver approximately 1.1 BCF of natural gas under
existing long-term contracts in the U.S.
A significant portion of Canadian Forest's natural gas production is sold
through the ProMark Netback Pool. At December 31, 1997 the ProMark Netback Pool
had entered into fixed price contracts to sell approximately 13.6 BCF of natural
gas in 1998 at an average price of $1.83 CDN per MCF and approximately 5.4 BCF
of natural gas in 1999 at an average price of approximately $2.16 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 1997, Canadian Forest supplied
27% of the gas for the Netback Pool.
At December 31, 1997 Saxon is obligated to deliver approximately .6 BCF of
natural gas in 1998 under an existing long-term contract. Saxon is further
obligated to deliver approximately 4.0 MMCF of natural gas per day through the
ProMark Netback Pool from January 1, 1998 through December 31, 2000.
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.
23
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* 49 26 Chairman of the Board and Chairman of the
Executive Committee. Chief Executive Officer
until December 1995. President until
November 1993. Chairman of the Nominating
Committee. Member of the Board of Directors
since 1982. Chairman of the Board of
Directors of Saxon Petroleum Inc.
Robert S. Boswell* 48 12 President since November 1993 and Chief
Executive Officer since December 1995. Vice
President until November 1993 and Chief
Financial Officer until December 1995.
Member of the Board of Directors since 1986.
Employed by the Company since October 1989.
Member of the Company's Executive Committee.
Director of C.E. Franklin Ltd. and Saxon
Petroleum Inc.
David H. Keyte 41 10 Executive Vice President and Chief Financial
Officer since November 1997. Vice President
and Chief Financial Officer since December
1995. Vice President and Chief Accounting
Officer from December 1993 until December
1995. Prior thereto Corporate Controller.
Chairman of the Company's Employee Benefits
Committee. Director of Saxon Petroleum Inc.
Forest D. Dorn 43 20 Senior Vice President-Gulf Coast Region since
November 1997. Vice President-Gulf Coast
Region since August 1996. Vice President
from February 1991 and General Business
Manager from December 1993 to August 1996.
24
Years with
Name (A) Age Forest Office (B)
-------- --- ------ ----------
Neal A. Stanley 50 1 Senior Vice President-Western Region since
November 1997. Vice President-Western Region
since August 1996. Prior thereto President
of Teton Oil and Gas Corporation.
V. Bruce Thompson 50 3 Senior Vice President-Marketing and
Administration and General Counsel since
November 1997. Vice President and General
Counsel since August 1994. Vice President -
Legal of Mid-America Dairymen, Inc. from
November 1993 to August 1994. Chief of Staff
for Oklahoma Congressman James M. Inhofe
until November 1993. Member of Company's
Employee Benefits Committee.
Donald H. Stevens 45 - Vice President-Capital Markets and Strategic
Initiatives since August 1997. Prior thereto
Vice President-Corporate Relations and
Capital Markets of Barrett Resources
Corporation.
Daniel G. Blanchard 37 3 Treasurer since November 1997 and Assistant
Treasurer since September 1994.
Daniel L. McNamara 52 26 Secretary and Corporate Counsel. Member of
the Company's Employee Benefits Committee.
Joan C. Sonnen 44 8 Controller since December 1993. Prior
thereto Director of Financial Accounting and
Reporting. Member of 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.
25
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 27, 1998, the Company's 37,320,228 shares of Common Stock were held
by 1,632 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 1996, 1997, or in the first quarter
of 1998.
High Low
---- ---
1996
----
First Quarter $16-1/2 $10-1/2
Second Quarter 13-5/8 11-1/4
Third Quarter 14-3/4 12-1/2
Fourth Quarter 17-7/8 12-3/8
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 (through March 20) $16-1/2 $13
$.75 CONVERTIBLE PREFERRED STOCK
On February 7, 1997, the Company called for redemption all 2,877,673 shares of
its $.75 Convertible Preferred Stock. The redemption price was $10.00 per share
plus accumulated and unpaid dividends to and including the date of redemption
(for an aggregate redemption price of $10.06 per share). In lieu of cash
redemption, prior to the close of business on February 21, 1997, the holders of
the preferred shares had the right to convert each share into 0.7 share of
Forest's Common Stock. As of February 21, 1997, 2,783,945 shares or 96.7% of
the shares outstanding were tendered for conversion into Common Stock. The
remaining 93,728 shares that were not tendered for conversion were redeemed by
the Company at the redemption price of $10.06 per share on February 28, 1997.
DIVIDEND RESTRICTIONS
The only 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 Indenture executed in connection with
Canadian Forest's 8 3/4% Senior Subordinated Notes due September 15, 2007
which are guaranteed by the Company and (iii) the Company's Third Amended and
Restated Credit Agreement dated February 3, 1998 with The Chase
26
Manhattan Bank (Chase), as agent for a group of banks, under which the Company
is restricted in amounts it may pay as dividends (other than dividends
payable in Common Stock). Under these dividend restrictions, the Company was not
prohibited from paying cash dividends on its Common Stock as of March 1, 1998.
The Company 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 payments of dividends, if any, on the Common Stock is within the
discretion of the Board of Directors and will depend on the Company'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 5, 8 and 9 of Notes to Consolidated Financial
Statements.
27
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
The following table sets forth selected data regarding the Company on a
historical basis as of and for each of the years in the five-year period ended
December 31, 1997. 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,
------------------------------------------------------------------
1997 1996 1995 1994 (1) 1993 (2)
---- ---- ---- -------- --------
(In Thousands Except Per Share Amounts and Volumes)
FINANCIAL DATA
Revenue:
Marketing and processing $184,399 187,374 - - -
Oil and gas sales 155,242 128,713 82,275 114,541 102,883
-------- ------- -------- ------- -------
Total revenue $339,641 316,087 82,275 114,541 102,883
Earnings (loss) before cumulative effects of changes in
accounting principles and extraordinary items $ 3,089 1,139 (17,996) (67,853) (9,355)
Net earnings (loss) $ (9,270) 3,305 (17,996) (81,843) (21,213)
Weighted average number of common shares outstanding 33,669 25,062 7,360 5,619 4,399
Net earnings (loss) attributable to common stock $(9,459) 1,147 (20,156) (84,004) (23,463)
Basic earnings (loss) per share:
Earnings (loss) attributable to common stock
before cumulative effect of changes in
accounting principles and extraordinary items $ .09 (.04) (2.74) (12.46) (2.64)
Cumulative effect of changes in accounting
principles - - - (2.49) (.26)
Extraordinary items (.37) .09 - - (2.44)
-------- ------- -------- ------- -------
Net earnings (loss) attributable to common stock $ (.28) .05 (2.74) (14.95) (5.34)
Diluted earnings (loss) per share:
Earnings (loss) attributable to common
stock before cumulative effect of changes in
accounting principles and extraordinary items $ .08 (.04) (2.74) (12.46) (2.64)
Cumulative effect of changes in accounting principles - - - (2.49) (.26)
Extraordinary items (.35) .09 - - (2.44)
-------- ------- -------- ------- -------
Net earnings (loss) attributable to common stock $ (.27) .05 (2.74) (14.95) (5.34)
Total assets $647,782 563,458 321,043 324,832 426,755
Long-term debt $254,760 168,859 193,879 207,054 194,307
Other long-term liabilities $ 51,787 53,560 27,139 28,166 27,053
Deferred revenue $ - 7,591 15,137 35,908 67,228
Shareholders' equity $261,827 242,443 44,297 6,086 88,156
28
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA (CONTINUED)
Years Ended December 31,
Pro Forma -----------------------------------------------
1997 (3) 1997 1996 1995 1994 (1) 1993 (2)
-------- ---- ---- ---- -------- --------
(In Thousands Except per Share Amounts and Volumes)
OPERATING DATA
Annual production (4):
Gas (MMCF) 49,035 42,496 33,342 48,048 41,114
Liquids (MBBLS) 3,207 2,749 1,173 1,543 1,493
Average price received (4):
Gas (per MCF) (5) $ 2.06 1.89 1.77 1.90 1.88
Liquids (per Barrel) $ 16.92 17.59 15.86 14.83 16.97
Capital expenditures, net of asset sales 147,130 234,556 44,913 29,839 168,169
Proved Reserves (4) (6):
Gas (MMCF) 487,291 378,315 337,250 238,128 246,996 273,382
Liquids (MBBLS) 37,250 24,636 24,014 10,541 7,532 8,198
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves (6) $705,137 439,570 559,869 256,917 207,549 262,176
Total discounted future net cash flows
relating to proved oil and gas reserves,
including amounts attributable to
volumetric production payments (6) $705,137 439,570 562,995 265,393 230,149 299,053
- ----------------
(1) Effective January 1, 1994 the Company changed its method of accounting for
oil and gas sales from the sales method to the entitlements method. See
Note 1 of Notes to Consolidated Financial Statements.
(2) Effective January 1, 1993, the Company adopted the provisions of Statements
of Financial Accounting Standards No. 106 and No. 109. These statements
required the Company to accrue the expected cost of postretirement benefits
and to adopt the liability method of accounting