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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 for income taxes,
respectively.
(3) The pro forma data as of December 31, 1997 gives effect to the Louisiana
Acquisition as if it occurred on that date. See Note 2 of Notes to
Consolidated Financial Statements.
(4) Includes amounts attributable to required deliveries under volumetric
production payments. See Notes 6 and 17 of Notes to Consolidated Financial
Statements.
(5) Amounts shown for 1995 exclude the effects of a gas contract settlement.
Including such amount, the average sales price for 1995 was $1.90 per MCF.
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.
(6) The 1997, 1996 and 1995 amounts include 100% of the reserves owned by
Saxon, a consolidated subsidiary in which the Company holds a majority
interest. See Note 2 of Notes to Consolidated Financial Statements.
29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis should be read in conjunction with the
Company's Consolidated Financial Statements and Notes thereto.
RESULTS OF OPERATIONS
The net loss for 1997 was $9,270,000 compared to net earnings of $3,305,000
in 1996. The net loss for 1997 includes an extraordinary loss on the
extinguishment of debt of $12,359,000 related to the tender offer for the
Company's 11 1/4% Senior Subordinated Notes and a $4,051,000 noncash loss on
currency translation relating to $125,000,000 of the 8 3/4% Notes which were
issued by Canadian Forest in September, 1997. Earnings for the 1996 period
include an extraordinary gain on extinguishment of debt of $2,166,000.
Earnings from operations in 1997 were $30,655,000 compared to $28,491,000 in
1996. The improved earnings from operations for 1997 were attributable
primarily to higher natural gas prices and increased production resulting
from the Company's successful drilling programs in 1996 and 1997.
Net earnings for 1996 were $3,305,000 compared to a net loss of $17,996,000
in 1995. The improved earnings from continuing operations in 1996 were
attributable primarily to increased natural gas and liquids prices, as well
as increased natural gas and liquids production as a result of the
acquisitions of Saxon Petroleum Inc. (Saxon) and Canadian Forest, which were
completed in December 1995 and January 1996, respectively, and to the
contribution made by ProMark, which was also acquired in January 1996.
The Company's marketing and processing revenue decreased by 2% to
$184,399,000 in 1997 from $187,374,000 in 1996 and the related marketing and
processing expense decreased by 2% to $175,847,000 in 1997 from $178,706,000
in the previous year. The gross margin reported for marketing and processing
activities was $8,552,000 in 1997 which is comparable to $8,668,000 in 1996.
The Company's oil and gas sales revenue increased by 21% to $155,242,000 in 1997
from $128,713,000 in 1996. Production volumes for natural gas in 1997 increased
15% from 1996 due primarily to discoveries in the Gulf of Mexico being brought
onto production. The average sales price received for natural gas in 1997
increased 9% compared to the average sales price received in 1996. Production
volumes for liquids (consisting of oil, condensate and natural gas liquids) were
17% higher in 1997 than in 1996 due primarily to new production from Gulf of
Mexico and Canadian properties. The average sales price received by the Company
for its liquids production during 1997 decreased 4% compared to the average
sales price received during 1996.
Oil and gas sales revenue increased to $128,713,000 in 1996 from $82,275,000 in
1995, or by approximately 56%. Oil and gas sales in 1995 included $4,263,000
of income associated with a gas contract settlement with Columbia Gas
Transmission (Columbia). The Company had entered into gas sales contracts with
Columbia which were rejected by Columbia in connection with its bankruptcy
proceedings. The income related to the settlement with Columbia represented
approximately 5% of total oil and gas sales in 1995. Natural gas and liquids
volumes increased 27% and 134% in 1996, respectively, primarily as a result of
the Canadian acquisitions and new production from the Company's offshore Gulf of
Mexico platform at High Island 116, partially offset by anticipated production
declines in the United States. The average sales price received for natural gas
in 1996 increased 7% compared to 1995, exclusive of the effects of income
associated with the gas contract settlement. The average sales price received
for liquids production in 1996 increased 11% compared to 1995.
Oil and gas production expense of $36,284,000 in 1997 increased 13% from
$32,199,000 in 1996 due primarily to expenses relating to new production from
Gulf of Mexico properties, temporary transportation expenses associated with the
Bigoray field in Alberta and the inclusion of twelve months of costs for
Canadian Forest in 1997 versus only eleven months in 1996. On an MCFE basis
(MCFE means thousands of cubic feet of natural gas equivalents, using conversion
ratio of one barrel of oil to six MCF of natural gas), production expense was
$.53 per MCFE in 1997 compared to $.55 in 1996.
30
Oil and gas production expense increased 43% to $32,199,000 in 1996 from
$22,463,000 in 1995 due primarily to production expense associated with the
newly-acquired Canadian properties. On an MCFE basis, production expense was
$.55 per MCFE in 1996 compared to $.56 in 1995.
Oil and gas sales to Enron and certain of its affiliates (Enron Affiliates), the
Company's largest customer, represented approximately 18% of oil and gas sales
in 1997, compared to 25% in 1996 and 38% in 1995. The decreases during these
periods are attributable primarily to the decreases in delivery requirements
pursuant to volumetric production payments. The Company's spot market sales to
Enron Affiliates were approximately 11 BCFE in both 1997 and 1996 and 8 BCFE in
1995.
31
The production volumes, weighted average sales prices and production expenses
for the years ended December 31, 1997, 1996 and 1995 for Forest and its
subsidiaries were as follows:
Year Ended December 31, 1997
-------------------------------------------------------------------
Gulf Total Total
Coast Western U.S. Canada Company
----- ------- ---- ------ -------
NATURAL GAS
Total production (MMCF) (1) 31,383 2,635 34,018 15,017 49,035
Sales price received (per MCF) $ 2.55 2.32 2.53 1.46 2.20
Effects of energy swaps (per MCF) (2) (.22) - (.21) - (.14)
-------- ----- ------ ------ ------
Average sales price (per MCF) $ 2.33 2.32 2.32 1.46 2.06
LIQUIDS
Oil and condensate:
Total production (MBBLS) 1,027 110 1,137 1,498 2,635
Sales price received (per BBL) $ 18.04 19.63 18.20 18.07 18.13
Effects of energy swaps (per BBL) (2) (.25) - (.23) (.08) (.15)
-------- ----- ------ ------ ------
Average sales price (per BBL) $ 17.79 19.63 17.97 17.99 17.98
Natural gas liquids:
Total production (MBBLS) 121 9 130 442 572
Average sales price (per BBL) $ 10.55 11.56 10.62 12.42 12.01
Total liquids production (MBBLS) 1,148 119 1,267 1,940 3,207
Average sales price (per BBL) $ 17.03 19.02 17.21 16.72 16.92
Total production (MMCFE) 38,271 3,349 41,620 26,657 68,277
Average sales price (per MCFE) $ 2.42 2.51 2.42 2.04 2.27
Operating expense (per MCFE) .46 1.02 .50 .58 .53
-------- ----- ------ ------ ------
Netback (per MCFE) $ 1.96 1.49 1.92 1.46 1.74
-------- ----- ------ ------ ------
-------- ----- ------ ------ ------
(1) Total natural gas production includes scheduled deliveries under volumetric
production payments, net of royalties, of 801 MMCF. Natural gas
delivered pursuant to volumetric production payment agreements represented
approximately 2% of total natural gas production. 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 17 of Notes to Consolidated Financial
Statements.
(2) Energy swaps were entered into to hedge the price of spot market volumes
against price fluctuations. Hedged natural gas volumes were 13,990 MMCF
and hedged oil and condensate volumes were 949,000 barrels. The aggregate
net loss under energy swap agreements was $7,439,000 for the period and was
accounted for as a reduction of oil and gas sales.
32
Year Ended December 31, 1996
--------------------------------------------------------------------
Gulf Total Total
Coast Western U.S. Canada Company
----- ------- ---- ------ -------
NATURAL GAS
Total production (MMCF) (1) 24,969 3,655 28,624 13,872 42,496
Sales price received (per MCF) $ 2.39 2.17 2.36 1.41 2.06
Effects of energy swaps (per MCF) (2) (.26) - (.23) (.04) (.17)
------- ----- ------ ------ ------
Average sales price (per MCF) $ 2.13 2.17 2.13 1.37 1.89
LIQUIDS
Oil and condensate:
Total production (MBBLS) (3) 831 133 964 1,308 2,272
Sales price received (per BBL) $ 19.88 20.92 20.03 20.64 20.38
Effects of energy swaps (per BBL) (2) (1.24) - (1.07) (1.82) (1.50)
------- ----- ------ ------ ------
Average sales price (per BBL) $ 18.64 20.92 18.96 18.82 18.88
Natural gas liquids:
Total production (MBBLS) 132 8 140 337 477
Average sales price (per BBL) $ 10.29 13.63 10.48 11.87 11.46
Total liquids production (MBBLS) 963 141 1,104 1,645 2,749
Average sales price (per BBL) $ 17.50 20.50 17.88 17.40 17.59
Total production (MMCFE) 30,747 4,501 35,248 23,742 58,990
Average sales price (per MCFE) $ 2.27 2.41 2.29 2.00 2.18
Operating expense (per MCFE) .53 .75 .56 .52 .55
------- ----- ------ ------ ------
Netback (per MCFE) $ 1.74 1.66 1.73 1.48 1.63
------- ----- ------ ------ ------
------- ----- ------ ------ ------
(1) Total natural gas production includes scheduled deliveries under volumetric
production payments, net of royalties, of 3,168 MMCF. Natural gas
delivered pursuant to volumetric production payment agreements represented
approximately 7% of total natural gas production. For further information
concerning volumes and prices recorded under volumetric production
payments, see Notes 6 and 17 of Notes to Consolidated Financial Statements.
(2) Energy swaps were entered into to hedge the price of spot market volumes
against price fluctuations. Hedged natural gas volumes were 12,741 MMCF
and hedged oil and condensate volumes were 895,600 barrels. The aggregate
net loss under energy swap agreements was $10,422,000 for the period and
was accounted for as a reduction of oil and gas sales.
(3) An immaterial amount of oil production was covered by scheduled deliveries
under volumetric production payments.
33
Year Ended
December 31, 1995
-----------------
U.S.
-----------------
NATURAL GAS
Total production (MMCF) (1) 33,342
Sales price received (per MCF) (2) $ 1.65
Effects of energy swaps (per MCF) (3) .12
-------
Average sales price (per MCF) (2) $ 1.77
LIQUIDS
Oil and condensate:
Total production (MBBLS) (4) 1,121
Sales price received (per BBL) $ 16.36
Effects of energy swaps (per BBL) (3) (.50)
-------
Average sales price (per BBL) $ 15.86
Natural gas liquids:
Total production (MBBLS) 52
Average sales price (per BBL) $ 15.81
Total liquids production (MBBLS) 1,173
Average sales price (per BBL) $ 15.86
Total production (MMCFE) 40,380
Average sales price (per MCFE) $ 2.04
Operating expense (per MCFE) .56
-------
Netback (per MCFE) $ 1.48
-------
-------
(1) Total natural gas production includes scheduled deliveries under volumetric
production payments, net of royalties, of 9,120 MMCF. Natural gas
delivered pursuant to volumetric production payment agreements represented
approximately 27% of total natural gas production. For further information
concerning volumes and prices recorded under volumetric production
payments, see Notes 6 and 17 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 Note 14 of
Notes to Consolidated Financial Statements.
(3) Energy swaps were entered into to hedge the price of spot market volumes
against price fluctuation. Hedged natural gas volumes were 10,146 MMCF
and hedged oil and condensate volumes were 498,000 barrels. The aggregate
net gain under energy swap agreements was $3,536,000 for the period and
was accounted for as an increase in oil and gas sales.
(4) An immaterial amount of oil production was covered by scheduled deliveries
under volumetric production payments.
34
General and administrative expense increased 24% to $16,864,000 in 1997 compared
to $13,623,000 in 1996 due primarily to a larger number of employees who were
hired to support the Company's increased operations and its expanded exploration
and development programs. General and administrative expense increased 50% to
$13,623,000 in 1996 compared to $9,081,000 in 1995 due primarily to the effect
of Canadian acquisitions. The capitalization rate was approximately 33% in 1997
compared to 36% in 1996 and 43% in 1995. Changes in the capitalization rate
result from changes in the percentage of employees' time spent working directly
on exploration and development projects.
Total overhead costs (capitalized and expensed general and administrative costs)
were $24,993,000 in 1997, $21,396,000 in 1996 and $15,857,000 in 1995. Total
overhead costs were approximately 17% higher in 1997 compared to 1996 due
primarily to the larger number of employees described above. Direct exploration
and development expenditures in 1997 were approximately $140,000,000 compared to
approximately $77,000,000 in 1996. Total overhead costs were approximately 35%
higher in 1996 compared to 1995 due primarily to the addition of the Canadian
operations. The following table summarizes the total overhead costs incurred
during the periods:
Years Ended December 31,
-----------------------------------
1997 1996 1995
---- ---- ----
(In Thousands)
Overhead costs capitalized $ 8,129 7,773 6,776
General and administrative costs expensed (1) 16,864 13,623 9,081
------- ------ ------
Total overhead costs $24,993 21,396 15,857
------- ------ ------
------- ------ ------
Number of salaried employees at end of year 202 179 115
------- ------ ------
------- ------ ------
(1) Includes $2,992,000 and $2,555,000 in 1997 and 1996, respectively, related
to marketing and processing operations.
Depreciation and depletion expense increased 27% to $79,991,000 in 1997 from
$63,068,000 in 1996 due to higher production and higher per-unit expense. The
depletion rate increased to $1.12 per MCFE in 1997 compared to $1.01 per MCFE in
1996, primarily as a result of higher per-unit development costs in the Gulf of
Mexico due to increased costs for services. Depreciation and depletion expense
increased 45% to $63,068,000 in 1996 from $43,592,000 in 1995 due to the
increase in production, offset by a decrease in the depletion rate per unit of
production. The depletion rate decreased to $1.01 per MCFE in 1996 compared to
$1.06 per MCFE in 1995, resulting from the addition of lower cost Canadian
production, partially offset by higher anticipated future costs for services in
the United States.
At December 31, 1997 the Company had undeveloped properties with a cost basis of
approximately $41,226,000 in the U.S. and $19,675,000 in Canada which were not
subject to depletion, compared to $30,046,000 in the U.S. and $13,870,000 in
Canada at December 31, 1996 and $28,380,000 in the U.S. at December 31, 1995.
The increase in 1997 compared to 1996 is due primarily to acquisitions of
undeveloped acreage in both the U.S. and Canada in 1997. The increase in 1996
compared to 1995 is due primarily to the acquisition of undeveloped properties
in the Canadian Forest purchase.
The Company was not required to record a writedown of the carrying value of its
United States or Canadian oil and gas properties in 1997, 1996 or 1995.
Writedowns of the full cost pools in the United States and Canada may be
required , however, if prices decline, undeveloped property values decrease,
estimated proved reserve volumes are revised downward or costs incurred in
exploration, development, or acquisition activities in the respective full cost
pools exceed the discounted future net cash flows from the additional reserves,
if any, attributable to each of the cost pools.
35
The average spot price received by the Company for natural gas produced in
the Gulf Coast decreased from $2.61 per MCF at December 31, 1997 to
approximately $2.26 per MCF at March 1, 1998. The West Texas Intermediate
price for crude oil decreased from $14.75 per barrel at December 31, 1997 to
approximately $12.25 per barrel at March 1, 1998. The average price received
for natural gas produced in Canada decreased from $2.10 CDN per MMBTU at
December 31, 1997 to approximately $1.75 CDN per MMBTU at March 1, 1998. The
average price received for crude oil produced in Canada decreased from $22.00
CDN per barrel at December 31, 1997 to approximately $18.90 CDN per barrel at
March 1, 1998.
Other income of $1,289,000 in 1997 included adjustments of royalty
liabilities in the U.S. and Canada. In the U.S., approximately $2,100,000 of
accrued royalties were reversed as a result of court decisions in Oklahoma.
In Canada, income of approximately $595,000 was recognized by Canadian Forest
following resolution of prior year crown royalty issues. The amount of
future crown royalty adjustments in Canada cannot be determined at this time,
but is not expected to be material to the Company's cash flow, results of
operations or financial position. Partially offsetting the favorable royalty
adjustments in 1997 was approximately $1,400,000 of expense recorded in the
U.S. as a result of a market value adjustment to the carrying value of land
purchased in 1982. In addition, Saxon recorded approximately $750,000 of
expense related to the potential sale of the company. Other income of
$1,387,000 in 1996 included the reversal of a $1,136,000 liability for
royalties on the proceeds from the gas contract settlement with Columbia.
Other income was $181,000 in 1995.
Interest expense of $21,403,000 in 1997 decreased $1,904,000 or 8% compared
to 1996 due primarily to the extinguishment of the nonrecourse secured loan
with JEDI in the fourth quarter of 1996 and the redemption of the Company's
11 1/4% Senior Subordinated Notes in September and October of 1997, offset in
part by interest charges on the 8 3/4% Notes and increased interest charges
on higher average outstanding balances under bank credit facilities
throughout most of 1997. Interest expense of $23,307,000 in 1996 decreased
$2,016,000 or 8% compared to 1995 due primarily to the restructuring and
extinguishment of the nonrecourse secured loan and lower effective interest
on the dollar denominated production payment.
Translation loss on subordinated debt of $4,051,000 in 1997 relates to
translation of the 8 3/4% Notes issued by Canadian Forest in September 1997,
and is attributable to the decline in the value of the Canadian dollar
relative to the U.S. dollar during the fourth quarter of 1997. The Company
is required to recognize the noncash foreign currency translation gains or
losses related to the 8 3/4% Notes because the debt is denominated in U.S.
dollars and the functional currency of Canadian Forest is the Canadian dollar.
LIQUIDITY AND CAPITAL RESOURCES
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 bank credit facilities and cash provided by operating
activities.
In 1996, 1997 and early 1998, the Company completed several transactions that
improved its financial position.
On January 31, 1996 the Company and Saxon sold 13,200,000 shares of Common Stock
for $11.00 per share in a public offering (the 1996 Public Offering). Of this
amount, 1,060,000 shares were sold by Saxon and 12,140,000 shares were sold by
Forest. The net proceeds to Forest from the issuance of the shares totaled
approximately $125,000,000 after deducting issuance costs and underwriting fees,
and were used, along with an additional approximately $8,300,000 drawn under the
Company's Credit Facility, to complete the purchase of Canadian Forest and
ProMark. The net proceeds to Saxon of approximately $11,000,000 were used to
reduce its bank debt.
On August 1, 1996 Anschutz exercised an option to purchase 2,250,000 shares of
Common Stock for $26,200,000 or approximately $11.64 per share. Proceeds
received by Forest were used primarily to fund a portion of 1996 capital
expenditures.
On November 5, 1996 the Company exchanged 2,000,000 shares of Common Stock plus
approximately $13,500,000 in cash to extinguish approximately $43,000,000 of
nonrecourse secured debt owed to JEDI. In connection with this transaction,
Anschutz acquired 1,628,888 shares of Common Stock by exercising warrants to
purchase 388,888 shares of Common Stock at $10.50 per share and by converting
620,000 shares of Forest's Second Series Preferred Stock into 1,240,000 shares
of Common Stock.
36
On November 14, 1996 the Company filed a shelf registration (the Shelf
Registration Statement) with the Securities and Exchange Commission to issue up
to $250,000,000 in one or more forms of debt or equity securities. Except as
otherwise provided in an applicable prospectus supplement, the net proceeds from
the sale of the securities will be used for the acquisition of oil and gas
properties, capital expenditures, the repayment of subordinated debentures or
other debt, repayments of borrowings under revolving credit agreements, or for
other general corporate purposes.
On February 7, 1997 the Company called for redemption all 2,877,673 shares of
its $.75 Convertible Preferred Stock. In response to its call for redemption,
2,783,945 shares or 96.7% of the shares outstanding were tendered for conversion
into Common Stock on or before the February 21, 1997 deadline. The remaining
93,728 preferred shares were redeemed by the Company at the redemption price of
$10.06 per share (at a total cost of $942,904) on February 28, 1997. Lehman
Brothers Inc. purchased 65,616 shares of Common Stock issued pursuant to the
Shelf Registration Statement to fund the cash requirement of the redemption in
accordance with the terms of its standby purchase agreement with Forest. This
conversion and redemption eliminated all outstanding preferred stock from the
Company's capital structure and eliminated approximately $2,200,000 of annual
preferred dividend payments.
On August 28, 1997 Anschutz acquired 3,500,000 shares of Common Stock through
the exercise of a warrant for $8.60 per share resulting in cash proceeds to
Forest of $30,100,000. The original exercise price was $10.50 per share. The
reduction in the exercise price offered to Anschutz reflected an approximate 10%
present value discount computed to the warrants' expiration date of July 27,
1999. Proceeds from the exercise were used to reduce borrowings under the
Company's bank credit facilities.
On September 29, 1997, pursuant to a tender offer, $90,233,000 of the
Company's outstanding $100,000,000 aggregate principal amount of 11 1/4%
Senior Subordinated Notes due 2003 (the 11 1/4% Notes) was tendered by the
holders of the 11 1/4% Notes. The purchase price for each $1,000 principal
amount of 11 1/4% Notes validly tendered and accepted was $1,096.96. On
October 17, 1997 an additional $1,091,000 aggregate principal amount of 11
1/4% Notes was tendered at a purchase price of $1,090.00 for each $1,000.00
principal amount. As a result of the tender offer, Forest recorded an
extraordinary loss of approximately $12,359,000 relating to the excess of the
tender price over the carrying amount of the 11 1/4% Notes, net of related
unamortized debt issuance costs.
On September 29, 1997 Canadian Forest completed an offering of $125,000,000
of 8 3/4% Notes, which were sold at 99.745% of par and guaranteed on a senior
subordinated basis by the Company. A portion of the proceeds was used to
fund the tender offer described above, a portion was used to repay the
outstanding balance under the Canadian Credit facility and the remainder was
used for working capital and to fund capital expenditures. The effects of
the tender and new offering are expected to result in estimated annual cash
savings of approximately $5,000,000 to $6,000,000 related to interest and
taxes.
On February 2, 1998 Canadian Forest issued $75,000,000 principal amount of
8 3/4% Notes, an add-on to the Company's $125,000,000 principal amount of
8 3/4% Notes that were issued in September 1997. The Company received net
proceeds of approximately $75,000,000, which were used to provide funds for
the acquisition of oil and gas properties in Louisiana described below.
On February 3, 1998 the Company purchased 13 oil and gas properties located
onshore Louisiana (the Louisiana Acquisition) for total consideration of
approximately $230,776,000. The consideration consisted of approximately
$216,557,000 in cash, funded primarily from the Company's bank credit
facility; the issuance of $75,000,000 principal amount of 8 3/4% Notes
described above; and 1,000,000 shares of the Company's Common Stock.
The Company also 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 consummation of the Anschutz
Transaction is subject to the completion of a definitive agreement and
approval of the transaction by the Company's shareholders, other
37
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 proved reserves associated with the Anschutz
Transaction.
Many of the factors which may affect the Company's future operating
performance and long-term liquidity are beyond the Company's control
including, but not limited to, oil and natural gas prices, governmental
actions and taxes, the availability and attractiveness of properties for
acquisition, the adequacy and attractiveness of financing and operational
results. The Company continues to examine alternative sources of long-term
capital, including bank borrowings, the issuance of debt instruments, the
sale of common stock, preferred stock or other equity securities of the
Company, the issuance of net profits interests, sales of non-strategic
assets, 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, some of which are beyond the control of the Company. In addition,
the prices the Company receives for its future oil and natural gas production
and the level of the Company's production will significantly impact future
operating cash flows. No prediction can be made as to the prices the Company
will receive for its future oil and gas production. At March 1, 1998 the
Company had four offshore Gulf of Mexico wells whose combined production
represents approximately 17% of the Company's consolidated daily
deliverability. The Company's production, revenue and cash flow could be
adversely affected if production from these properties decreases to a
significant degree.
BANK CREDIT FACILITIES. At December 31, 1997 the Company and its
subsidiaries, Canadian Forest and ProMark, had a $250,000,000 global credit
facility (the Global Credit Facility) which provided for a global borrowing
base of $130,000,000 through a syndicate of banks led by The Chase Manhattan
Bank and The Chase Manhattan Bank of Canada. The borrowing base is subject
to semi-annual redeterminations. Under the Global Credit Facility, the
Company can allocate the global borrowing base between the United States and
Canada, subject to specified limitations. Funds borrowed under the Global
Credit Facility can be used for general corporate purposes. Under the terms
of the Global Credit Facility, the Company, Canadian Forest and ProMark are
subject to certain covenants and financial tests, including restrictions or
requirements with respect to working capital, cash flow, additional debt,
liens, asset sales, investments, mergers, cash dividends and reporting
responsibilities.
The Global Credit Facility is secured by a lien on, and a security interest
in, a portion of the Company's U.S. proved oil and gas properties, related
assets, pledges of accounts receivable, and a pledge of 66% of the capital
stock of Canadian Forest. The Global Credit Facility is also indirectly
secured by substantially all of the assets of Canadian Forest.
On February 3, 1998, the Company amended the Global Credit Facility. The
primary purpose of the amendment was to increase the credit facility to
$300,000,000 and the borrowing base to $260,000,000 in order to finance the
Louisiana Acquisition. Under the amended Global Credit Facility, the maximum
credit facility allocations in the United States and Canada are $275,000,000
and $25,000,000, respectively. The global borrowing base is currently
allocated $250,000,000 to the United States and $10,000,000 to Canada.
At February 28, 1998, the outstanding borrowings under the Global Credit
Facility were $224,900,000 in the U.S. and there were no outstanding
borrowings in Canada. The Company has used the Global Credit Facility for
Letters of Credit in the amount of $233,000 in the U.S. $4,522,000 CDN in
Canada.
In addition to the credit facilities described above, Saxon has a credit
facility (the Saxon Credit Facility) with a borrowing base of $39,800,000
CDN. The loan is subject to semi-annual review and has demand features;
however, repayments are not required provided that borrowings are not in
excess of the borrowing base and Saxon complies with other existing
covenants. At February 28, 1998 the outstanding balance under this facility
was $37,310,000 CDN.
WORKING CAPITAL. The Company had a working capital surplus of approximately
$22,062,000 at December 31, 1997 compared to a deficit of approximately
$12,649,000 at December 31, 1996. The surplus at December 31, 1997 is
38
due primarily to unapplied proceeds of $12,530,000 in Canada from the
offering of the 8 3/4% Notes which was completed on September 29, 1997.
These funds will be used in Canada to fund a portion of the 1998 capital
expenditure program and for general corporate purposes.
In the U.S., the Company periodically reports working capital deficits at the
end of a period. Such working capital deficits are principally the result of
accounts payable for capitalized exploration and development costs. Settlement
of these payables is funded by cash flow from the Company's operations or, if
necessary, by drawdowns on the Company's long-term bank credit facilities. For
cash management purposes, drawdowns on the credit facilities are not made until
the due dates of the payables.
CASH FLOW. Historically, one of the Company's primary sources of capital has
been net cash provided by operating activities. Net cash provided by
operating activities decreased to $60,535,000 in 1997 compared to $70,442,000
in 1996 due primarily to increased production as well as higher natural gas
prices being more than offset by funds used for the settlement of volumetric
production payment obligations. The Company used $151,638,000 for investing
activities in 1997 compared to $226,870,000 in 1996. The 1996 outlays
included $136,191,000 for the acquisition of Canadian Forest, whereas the
1997 outlays consist primarily of exploration and development costs. Cash
provided by financing activities in 1997 was $101,233,000 in 1996 compared to
$161,876,000 in 1996. The 1997 period included cash inflows of $121,479,000
from the issuance of the 8 3/4% Notes, $30,100,000 proceeds from the exercise
of a warrant by Anschutz and net bank borrowings of $53,059,000, offset by
$100,303,000 used for the redemption of a portion of the Company's 11 1/4%
Notes. The 1996 period included $136,073,000 of net proceeds from a public
offering of Common Stock (the 1996 Public Offering).
Net cash provided by operating activities increased to $70,442,000 in 1996
compared to a net use of cash for operating activities of $5,452,000 in 1995.
The increase is attributable primarily to higher natural gas and liquids prices,
increased natural gas and liquids production as a result of the Saxon and
Canadian Forest acquisitions, the contribution made by ProMark and an increase
in accounts payable during 1996. The Company used $226,870,000 for investing
activities in 1996 compared to $17,710,000 in 1995. The increase is due
primarily to the use of funds to acquire Canadian Forest and higher capital
expenditures. Cash provided by financing activities was $161,876,000 in 1996
compared to $23,579,000 in 1995. The increase is due primarily to the net
proceeds received from the 1996 Public Offering and the exercise by Anschutz of
options and warrants.
39
CAPITAL EXPENDITURES. The Company's expenditures for property acquisition,
exploration and development for the past three years were as follows:
Years Ended December 31,
--------------------------------------
1997 1996 1995
---- ---- ----
(In Thousands)
Property acquisition costs (1):
Proved properties $ 7,499 140,875 26,487
Undeveloped properties 880 18,080 320
-------- ------- ------
8,379 158,955 26,807
Exploration costs:
Direct costs 61,851 40,831 11,528
Overhead capitalized 3,587 2,608 1,211
-------- ------- ------
65,438 43,439 12,739
Development costs:
Direct costs 77,836 36,559 7,633
Overhead capitalized 4,542 5,165 5,565
-------- ------- ------
82,378 41,724 13,198
-------- ------- ------
$156,195 244,118 52,744
-------- ------- ------
-------- ------- ------
(1) 1996 amounts consist primarily of the allocation of purchase price to the
oil and gas properties acquired in the purchase of Canadian Forest. 1995
amounts consist primarily of the allocation of purchase price to the oil
and gas properties acquired in the purchase of Saxon.
The Company's budgeted 1998 expenditures for exploration and development are
approximately $130,000,000. The Company intends to meet its 1998 capital
expenditure financing requirements using cash flows generated by operations,
sales of non-strategic assets and borrowings under existing lines of credit.
There can be no assurance, however, that the Company will have access to
sufficient capital to meet its capital requirements. The planned levels of
capital expenditures could be reduced if the Company experiences lower than
anticipated net cash provided by operations or other liquidity needs or could be
increased if the Company experiences increased cash flow or accesses additional
sources of capital.
In addition, while the Company intends to continue a strategy of acquiring
reserves that meet its investment criteria, no assurance can be given that the
Company can locate or finance any property acquisitions.
DISPOSITIONS OF NON-STRATEGIC ASSETS. As a part of its operating strategy, the
Company also conducts an ongoing disposition program of its non-strategic
assets. Assets with little value or which are not consistent with the Company's
ongoing operating strategy are identified for sale or trade. At the present
time, the Company has offered for sale property packages in each of its
operating regions. Properties offered for sale comprise approximately 38.7
BCFE or 5% of the Company's current reserve base.
During 1997, the Company disposed of properties with estimated proved reserves
of approximately 4.1 BCF of natural gas and 257,000 barrels of oil for total net
proceeds of $9,669,000.
During 1996, the Company disposed of properties with estimated proved reserves
of approximately 1.5 BCF of natural gas and 628,000 barrels of oil for total net
proceeds of $6,916,000. In addition, Saxon received proceeds of approximately
$10,959,000 representing the liquidation of its preferred shares in Archean
Energy Ltd. These shares,
40
which were received through a series of transactions relating to the 1992
sale of the Company's Canadian oil and gas properties, were transferred to
Saxon by Forest in 1995.
In 1995 the Company disposed of properties with estimated proved reserves of
approximately 2.4 BCF of natural gas and 6,000 barrels of oil for total net
proceeds of $8,715,000.
INVESTMENT IN SAXON PETROLEUM INC. The board of directors of Saxon has
created a special committee of independent directors, which has engaged a
third party to assess the asset base of Saxon and to determine strategic
alternatives to maximize shareholder value. The Company anticipates that
this assessment may result in a transaction in which Forest would either sell
its entire interest in Saxon or seek to acquire all or a portion of the
minority interest. No assurance can be given as to whether any such
transaction will occur or as to the terms thereof.
LONG-TERM SALES CONTRACTS. 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.
HEDGING PROGRAM. In addition to the volumes of natural gas and oil sold
under long-term sales contracts, the Company also uses energy swaps and other
financial agreements to hedge against the effects of fluctuations in the
sales prices for oil and natural gas produced. In a typical swap agreement,
the Company receives the difference between a fixed price per unit of
production and a price based on an agreed upon third-party index if the index
price is lower. If the index price is higher, the Company pays the
difference. The Company's current swaps are settled on a monthly basis. At
December 31, 1997 the Company had natural gas swaps for an aggregate of
approximately 33 BBTU (billion British Thermal Units) per day of natural gas
during 1998 at fixed prices ranging from $1.09 per MMBTU (million British
Thermal Units) on an Alberta Energy Company "C" (AECO "C") basis to $3.66 per
MMBTU on a New York Mercantile Exchange (NYMEX) basis and an aggregate of
approximately 3 BBTU per day of natural gas during 1999 at fixed prices
ranging from $2.02 to $2.71 per MMBTU (NYMEX basis). The weighted average
hedged price for natural gas under such agreements is $2.17 and $2.21 per
MMBTU in 1998 and 1999, respectively. At December 31, 1997 the Company had
oil swaps for an aggregate of 1,323 barrels per day of oil during 1998 at
fixed prices ranging from $20.00 to $20.62 per barrel (NYMEX basis). The
weighted average hedged price for oil under such agreements is $20.54 per
barrel.
Subsequent to December 31, 1997 the Company entered into eight additional
natural gas swaps. The swaps are for 36,000 MMBTU of natural gas per day
from March 1998 to November 1998 at fixed prices ranging from $1.62 per
MMBTU (AECO "C", U.S. $ basis) to $2.35 per MMBTU (NYMEX basis), with a
weighted average price of $2.29 per MMBTU.
YEAR 2000 ISSUES. In 1996, the Company commenced a year 2000 date conversion
project. The project addresses the effects the year 2000 will have on the
Company's software applications and analyzes upgrades and purchases that may
be required. The Company has completed its analysis of its land, accounting
and oil and gas reserves applications and expects to complete analysis of
its other applications by June 1998. The estimated cost of hardware and
software upgrades and purchases that may be required and the time required
for implementation are expected to be determined at that time. Based upon
the findings through March 1, 1998, the estimated costs of upgrades and
purchases are not expected to be significant.
RECENT ACCOUNTING PRONOUNCEMENTS. In June of 1997, the Financial Accounting
Standards Board issued Statements of Financial Accounting Standards No. 130,
Reporting Comprehensive Income (Statement No. 130) and No. 131, Disclosures
About Segments of an Enterprise and Related Information (Statement No. 131),
effective for years beginning after December 15, 1997. Statement No. 130
establishes standards for reporting and display of comprehensive income and
its components in a full set of general-purpose financial statements.
Statement No. 131 establishes standards for reporting information about
operating segments and the methods by which such segments
41
were determined. The Company has not yet adopted Statement No. 130 or
Statement No. 131. In February 1998, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 132, Employers'
Disclosures about Pensions and Other Postretirement Benefits (Statement No.
132), effective for years beginning after December 15, 1997. Statement No.
132 revises employers' disclosures about pension and other postretirement
benefit plans. It does not change the measurement of recognition of those
plans. The Company will comply with the reporting and display requirements
of these statements when required.
42
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information concerning this Item begins on the following page.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
43
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders
Forest Oil Corporation:
We have audited the accompanying consolidated balance sheets of Forest Oil
Corporation and subsidiaries as of December 31, 1997 and 1996, and the
related consolidated statements of operations, shareholders' equity, and cash
flows for each of the years in the three-year period ended December 31, 1997.
These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Forest
Oil Corporation and subsidiaries as of December 31, 1997 and 1996, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 1997 in conformity with generally
accepted accounting principles.
KPMG PEAT MARWICK LLP
Denver, Colorado
February 10, 1998
44
FOREST OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
1997 1996
--------- --------
(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 18,191 8,626
Accounts receivable 65,720 55,462
Other current assets 4,649 4,996
--------- --------
Total current assets 88,560 69,084
Net property and equipment, at cost,
full cost method (Notes 5 and 6) 521,293 458,242
Goodwill and other intangible assets, net 26,243 29,439
Other assets 11,686 6,693
--------- --------
$ 647,782 563,458
--------- --------
--------- --------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt (Note 5) $ - 2,091
Accounts payable 59,719 69,493
Accrued interest 4,152 4,584
Other current liabilities 2,627 5,565
--------- --------
Total current liabilities 66,498 81,733
Long-term debt (Notes 3 and 5) 254,760 168,859
Other liabilities 17,020 19,844
Deferred revenue (Note 6) - 7,591
Deferred income taxes 34,767 33,716
Commitments and contingencies
(Notes 10, 11 and 12)
Minority interest (Note 2) 12,910 9,272
Shareholders' equity (Notes 2, 3, 5, 8 and 9):
Preferred stock - 15,827
Common stock, 36,320,236 shares in 1997
(30,541,505 shares in 1996) 3,632 3,053
Capital surplus 485,686 438,556
Accumulated deficit (223,460) (214,190)
Foreign currency translation (4,031) (803)
--------- --------
Total shareholders' equity 261,827 242,443
--------- --------
$ 647,782 563,458
--------- --------
--------- --------
See accompanying Notes to Consolidated Financial Statements.
45
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31,
1997 1996 1995
------ ------ ------
(In Thousands Except Per Share Amounts)
Revenue:
Marketing and processing $184,399 187,374 -
Oil and gas sales:
Gas 100,993 80,111 59,084
Gas contract settlement (Note 14) - - 4,263
Oil, condensate and natural gas liquids 54,249 48,602 18,928
------- ------- -------
Total oil and gas sales 155,242 128,713 82,275
------- ------- -------
Total revenue 339,641 316,087 82,275
Operating expenses:
Marketing and processing 175,847 178,706 -
Oil and gas production 36,284 32,199 22,463
General and administrative 16,864 13,623 9,081
Depreciation and depletion 79,991 63,068 43,592
------- ------- -------
Total operating expenses 308,986 287,596 75,136
------- ------- -------
Earnings from operations 30,655 28,491 7,139
Other income and expense:
Other income, net (1,289) (1,387) (181)
Interest expense 21,403 23,307 25,323
Minority interest in earnings
(loss) of subsidiary 108 (19) -
Translation loss on subordinated debt 4,051 - -
------- ------- -------
Total other income and expense 24,273 21,901 25,142
------- ------- -------
Earnings (loss) before income taxes and
extraordinary item 6,382 6,590 (18,003)
Income tax expense (benefit) (Note 7):
Current 707 3,943 (7)
Deferred 2,586 1,508 -
------- ------- -------
3,293 5,451 (7)
Earnings (loss) before extraordinary item 3,089 1,139 (17,996)
Extraordinary item - gain (loss) on extinguishment
of debt (Notes 3 and 5) (12,359) 2,166 -
------- ------- -------
Net earnings (loss) $ (9,270) 3,305 (17,996)
------- ------- -------
------- ------- -------
Earnings (loss) attributable to common stock $ (9,459) 1,147 (20,156)
------- ------- -------
------- ------- -------
Weighted average number of common shares
outstanding 33,669 25,062 7,360
------- ------- -------
------- ------- -------
Basic earnings (loss) per common share:
Earnings (loss) attributable to common
stock before extraordinary item $ .09 (.04) (2.74)
Extraordinary item - gain (loss) on
extinguishment of debt (.37) .09 -
------- ------- -------
Earnings (loss) attributable to common stock $ (.28) .05 (2.74)
------- ------- -------
Diluted earnings (loss) per common share:
Earnings (loss) attributable to common stock
before extraordinary item $ .08 (.04) (2.74)
Extraordinary item - gain (loss)
on extinguishment of debt (.35) .09 -
------- ------- -------
Earnings (loss) attributable to common stock $ (.27) .05 (2.74)
See accompanying Notes to Consolidated Financial Statements.
46
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
COMMON
SHARES TO BE ACCUMU- FOREIGN
PREFERRED COMMON CAPITAL ISSUED IN DEBT LATED CURRENCY TREASURY
STOCK STOCK SURPLUS RESTRUCTURING DEFICIT TRANSLATION STOCK
--------- ------ ------- ------------- ------- ----------- ------
(In Thousands)
Balance December 31, 1994 $ 15,845 566 192,337 - (199,499) (1,337) (1,826)
Net loss - - - - (17,996) - -
Second Series Convertible Preferred Stock,
Common Stock and Warrants issued to
Anschutz (Notes 3, 8 and 9) 8,518 376 36,106 - - - -
Warrants issued to JEDI (Note 3) - - 12,117 - - - -
Costs associated with equity issued to
Anschutz and JEDI (Note 3) - - (3,940) - - - -
Common Stock issued in acquisition of
Saxon (Notes 2 and 9) - 106 9,434 - - - (9,540)
Common Stock issued to the Retirement
Savings Plan (Note 10) - 2 (1,425) - - - 1,826
$.75 Convertible Preferred Stock
dividends paid in cash (Note 8) - - (540) - - - -
$.75 Convertible Preferred Stock dividends
paid in Common Stock (Note 8) - 16 (16) - - - -
Conversion of $.75 Convertible Preferred
Stock to Common Stock (Note 8) (4) - 4 - - - -
Common shares to be issued in JEDI
Exchange (Note 3) - - - 6,073 - - -
Unfunded pension liability (Note 10) - - (2,836) - - - -
Foreign currency translation - - - - - (70) -
--------- ------ ------- ------ --------- ------- -------
Balance December 31, 1995 24,359 1,066 241,241 6,073 (217,495) (1,407) (9,540)
Net earnings - - - - 3,305 - -
Common Stock issued, net of offering
costs and minority interest effect of
$706,000 (Note 9) - 1,214 124,613 - - - 9,540
Common Stock issued in JEDI Exchange (Note 3) - 168 5,905 (6,073) - - -
Anschutz Option exercised (Notes 3 and 9) - 225 25,962 - - - -
Anschutz A Warrant exercised (Notes 3 and 9) - 39 4,044 - - - -
Common Stock issued to JEDI (Note 3) - 200 26,736 - - - -
Public Warrants exercised (Note 9) - 2 334 - - - -
Conversion of Second Series Preferred
Stock to Common Stock (Note 8) (8,518) 124 8,394 - - - -
Employee stock options exercised (Note 9) - 3 398 - - - -
Common Stock issued to the Retirement
Savings Plan and other (Note 10) - 3 398 - - - -
$.75 Convertible Preferred Stock dividends
paid in cash (Note 8) - - (1,619) - - - -
$.75 Convertible Preferred Stock dividends
paid in Common Stock (Note 8) - 9 (9) - - - -
Conversion of $.75 Convertible Preferred
Stock to Common Stock (Note 8) (14) - 14 - - - -
Unfunded pension liability (Note 10) - - 2,145 - - - -
Foreign currency translation - - - - - 604 -
--------- ------ ------- ------ --------- ------- -------
BALANCE DECEMBER 31, 1996 15,827 3,053 438,556 - (214,190) (803) -
NET LOSS - - - - (9,270) - -
ANSCHUTZ A WARRANT EXERCISED (NOTES 3 AND 9) - 350 29,750 - - - -
$.75 CONVERTIBLE PREFERRED STOCK
REDEMPTION (NOTE 8) (15,827) 202 14,825 - - - -
COMMON STOCK ISSUED TO SUBSIDIARY (NOTE 9) - 20 2,797 - - - (2,817)
COMMON STOCK SOLD BY SUBSIDIARY (NOTE 9) - - - - - - 2,817
EMPLOYEE OPTIONS EXERCISED (NOTE 9) - 5 607 - - - -
RESTRICTED STOCK BONUS AWARDS (NOTE 9) - 2 214 - - - -
UNFUNDED PENSION LIABILITY (NOTE 10) - - (1,063) - - - -
FOREIGN CURRENCY TRANSLATION - - - - - (3,228) -
--------- ------ ------- ------ --------- ------- -------
BALANCE DECEMBER 31, 1997 $ - 3,632 485,686 - (223,460) (4,031) -
--------- ------ ------- ------ --------- ------- -------
--------- ------ ------- ------ --------- ------- -------
See accompanying Notes to Consolidated Financial Statements.
47
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31,
1997 1996 1995
------ ------ ------
(In Thousands)
Cash flows from operating activities:
Net earnings (loss) before extraordinary item $ 3,089 1,139 (17,996)
Adjustments to reconcile net earnings (loss) to net cash
provided (used) by operating activities:
Depreciation and depletion 79,991 63,068 43,592
Translation loss on subordinated debt 4,051 - -
Amortization of deferred debt costs 942 1,253 1,015
Deferred income tax expense 2,586 1,508 -
Interest added to principal - 3,059 574
Minority interest in net earnings (loss) of subsidiary 108 (19) -
Other, net 619 792 1,714
(Increase) decrease in accounts receivable (5,954) (17,441) 4,285
Increase in other current assets (5,168) (921) (152)
Increase (decrease) in accounts payable (1,403) 22,044 (13,848)
Increase (decrease) in accrued interest
and other current liabilities (9,970) 3,506 (3,865)
Settlement of volumetric production payment obligation (6,832) - -
Amortization of deferred revenue (1,524) (7,546) (20,771)
--------- ------- --------
Net cash provided (used) by operating activities 60,535 70,442 (5,452)
Cash flows from investing activities:
Acquisition of subsidiaries:
Current assets - (22,304) (1,437)
Property and equipment - (144,099) (26,530)
Goodwill and other intangible assets - (31,163) -
Current liabilities - 23,562 2,139
Long-term debt - 701 16,183
Other liabilities - 1,376 -
Deferred taxes - 35,575 353
Minority interest - - 8,171
--------- ------- --------
Cash paid for acquisitions of subsidiaries - (136,352) (1,121)
Capital expenditures for property and equipment (156,799) (108,332) (27,098)
Proceeds from sales of assets 9,669 17,875 8,715
(Increase) decrease in other assets, net (4,508) (61) 1,794
--------- ------- --------
Net cash used by investing activities (151,638) (226,870) (17,710)
Cash flows from financing activities:
Proceeds from bank borrowings 279,068 194,018 82,600
Repayments of bank borrowings (226,009) (176,641) (91,800)
Repayments of production payment obligation (2,592) (3,622) (2,316)
Issuance of 8 3/4% senior subordinated
notes, net of issuance costs 121,479 - -
Redemption of 11 1/4% senior subordinated notes (100,303) - -
Repayments of nonrecourse secured loan - (13,881) (1,143)
Proceeds from capital stock and warrants issued, net 2,817 136,073 41,060
Proceeds from exercise of warrants 30,100 30,606 -
Proceeds from exercise of options 2,361 1,339 -
Costs of preferred stock conversion (800) - -
Payment of preferred stock dividends (540) (1,079) (540)
Decrease in other liabilities, net (4,348) (4,937) (4,282)
--------- ------- --------
Net cash provided by financing activities 101,233 161,876 23,579
Effect of exchange rate changes on cash (565) (109) 1
--------- ------- --------
Net increase in cash and cash equivalents 9,565 5,339 418
Cash and cash equivalents at beginning of year 8,626 3,287 2,869
--------- ------- --------
Cash and cash equivalents at end of year $ 18,191 8,626 3,287
--------- ------- --------
--------- ------- --------
Cash paid during the year for:
Interest $ 20,999 15,040 22,138
Income taxes $ 4,105 3,428 -
See accompanying Notes to Consolidated Financial Statements.
48
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
- -------------------------------------------------------------------------------
BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION - Forest Oil
Corporation is 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 publicly held since 1969. The Company is active
in several of the major exploration and producing areas in and offshore the
United States and in Canada.
The consolidated financial statements include the accounts of Forest Oil
Corporation and its consolidated subsidiaries (Forest or the Company).
Significant intercompany balances and transactions are eliminated. The
Company generally consolidates all subsidiaries in which it controls over 50%
of the voting interests. Entities in which the Company does not have a
direct or indirect majority voting interest are generally accounted for using
the equity method.
In the course of preparing the consolidated financial statements, management
makes various assumptions and estimates to determine the reported amounts of
assets, liabilities, revenue and expenses, and in the disclosures of
commitments and contingencies. Changes in these assumptions and estimates
will occur as a result of the passage of time and the occurrence of future
events and, accordingly, actual results could differ from amounts estimated.
Unless otherwise indicated, all share amounts, share prices and per share
amounts have been adjusted to give effect to a 5 to 1 reverse stock split
that was effective on January 8, 1996.
CASH EQUIVALENTS - For purposes of the statements of cash flows, the Company
considers all debt instruments with original maturities of three months or
less to be cash equivalents.
PROPERTY AND EQUIPMENT - The Company uses the full cost method of accounting
for oil and gas properties. Separate cost centers are maintained for each
country in which the Company has operations. During 1997 and 1996, the
Company's oil and gas operations were conducted in the United States and in
Canada. During 1995, the Company's oil and gas operations were conducted
solely in the United States. All costs incurred in the acquisition,
exploration and development of properties (including costs of surrendered and
abandoned leaseholds, delay lease rentals, dry holes and overhead related to
exploration and development activities) are capitalized. Capitalized costs
applicable to each cost center are depleted using the units of production
method. A reserve is provided for estimated future costs of site
restoration, dismantlement and abandonment activities as a component of
depletion. Unusually significant investments in unproved properties,
including related capitalized interest costs, are not depleted pending the
determination of the existence of proved reserves. As of December 31, 1997,
1996 and 1995, there were undeveloped property costs of $41,226,000,
$30,046,000 and $28,380,000, respectively, which were not being depleted in
the United States and at December 31, 1997 and 1996 there were costs of
$19,675,000 and $13,870,000 which were not being depleted in Canada. Of the
undeveloped costs in the United States not being depleted at December 31,
1997, approximately 45% were incurred in 1997, 20% in 1996, 2% in 1995, 2% in
1994, 29% in 1993 and 2% in 1992. Of the undeveloped costs in Canada not
being depleted at December 31, 1997, 54% were incurred in 1997 and 46% in
1996.
Depletion per unit of production was determined based on conversion to common
units of measure using one barrel of oil as an equivalent to six thousand
cubic feet (MCF) of natural gas. Depletion per unit of production (MCFE) for
each of the Company's cost centers was as follows:
United States Canada
------------- ------
1997 $1.24 .93
1996 1.12 .85
1995 1.06 -
49
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED):
- -------------------------------------------------------------------------------
Pursuant to full cost accounting rules, capitalized costs less related
accumulated depletion and deferred income taxes for each cost center may not
exceed the sum of (1) the present value of future net revenue from estimated
production of proved oil and gas reserves; plus (2) the cost of properties
not being amortized, if any; plus (3) the lower of cost or estimated fair
value of unproved properties included in the costs being amortized, if any;
less (4) income tax effects related to differences in the book and tax basis
of oil and gas properties. There were no provisions for impairment of oil
and gas properties in 1997, 1996 or 1995.
Gain or loss is recognized only on the sale of oil and gas properties
involving significant reserves.
Buildings, transportation and other equipment are depreciated on the
straight-line method based upon estimated useful lives of the assets ranging
from five to forty-five years.
Net property and equipment at December 31 consists of the following:
1997 1996
------ ------
(In Thousands)
Oil and gas properties $ 1,594,443 1,457,212
Buildings, transportation and
other equipment 11,157 10,993
----------- ----------
1,605,600 1,468,205
Less accumulated depreciation,
depletion and valuation allowance (1,084,307) (1,009,963)
----------- ----------
$ 521,293 458,242
----------- ----------
----------- ----------
GOODWILL AND OTHER INTANGIBLE ASSETS - Goodwill and other intangible assets
recorded in the acquisition of the Company's gas marketing subsidiary consist
of the following at December 31, 1997 and 1996:
1997 1996
------ ------
(In Thousands)
Goodwill $16,029 16,728
Gas marketing contracts 13,986 14,594
------- ------
30,015 31,322
Less accumulated amortization (3,772) (1,883)
------- ------
$26,243 29,439
------- ------
------- ------
Goodwill is being amortized on a straight line basis over twenty years. The
amount attributed to the value of gas marketing contracts acquired is being
amortized on a straight line basis over the average life of such contracts of
twelve years.
GAS MARKETING - The Company's gas marketing subsidiary, ProMark, enters into
fixed price agreements to purchase and sell natural gas. ProMark's general
strategy for this business is to enter into offsetting purchase and sales
contracts. Net open positions relating to these contracts do occur, but have
not been significant to date. Revenue from the sale of the gas is recorded
as marketing revenue and the cost of the gas sold is recorded as marketing
expense. ProMark also provides natural gas marketing aggregation services for
third parties. Fees earned for such services are recorded as marketing
revenue as the services are performed.
50
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED):
- -------------------------------------------------------------------------------
OIL AND GAS SALES - The Company accounts for oil and gas sales on the
entitlements method. Under the entitlements method, revenue is recorded
based upon the Company's share of volumes sold, regardless of whether the
Company has taken its proportionate share of volumes produced. The Company
records a receivable or payable to the extent it receives less or more than
its proportionate share of the related revenue.
As of December 31, 1997 the Company had produced approximately 2.0 BCF more
than its entitled share of production. The estimated value of this imbalance
of approximately $4,332,000 is included in the accompanying consolidated
balance sheet as a short-term liability of $1,347,000 and a long-term
liability of $2,985,000.
HEDGING TRANSACTIONS - In order to minimize exposure to fluctuations in oil
and natural gas prices, the Company hedges the price of future oil and
natural gas production by entering into certain contracts and financial
arrangements. These instruments are accounted for as hedges when the
instrument is designated as a hedge of the related production and there
exists a high degree of correlation between the fair value of the instrument
and the fair value of the hedged production. The degree of correlation is
assessed periodically. In the event that an instrument does not meet the
designation or effectiveness criteria, any gain or loss on the instrument is
recognized immediately in earnings. Otherwise, gains and losses related to
hedging transactions are recognized as adjustments to the revenue recorded
for the related production. If an instrument is settled early, any gains
or losses are deferred and recognized as adjustments to the revenue recorded
for the related production. Costs associated with the purchase of certain
hedging instruments are also deferred and amortized against revenue related
to the hedged production.
INCOME TAXES - The Company uses the asset and liability method of accounting
for income taxes which requires the recognition of deferred tax liabilities
and assets for the expected future tax consequences of temporary differences
between financial accounting bases and tax bases of assets and liabilities.
FOREIGN CURRENCY TRANSLATION - The functional currency of the Company's
Canadian operations is the Canadian dollar. Assets and liabilities related
to the Company's Canadian operations are generally translated at current
exchange rates, and related translation adjustments are reported as a
component of shareholders' equity. Income statement accounts are translated
at the average rates during the period. The Company is also required to
recognize foreign currency translation gains or losses related to its 8 3/4%
Senior Subordinated Notes due 2007 (the 8 3/4% Notes) 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.
EARNINGS (Loss) PER SHARE - In February 1997, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 128,
Earnings per Share (Statement No. 128) effective for periods ending after
December 15, 1997. Statement No. 128 changes the computation, presentation
and disclosure requirements for earnings per share for entities with publicly
held common stock or potential common stock. Under such requirements the
Company is required to present both basic earnings per share and diluted
earnings per share. Basic earnings (loss) per share is computed by dividing
net earnings (loss) attributable to common stock by the weighted average
number of common shares outstanding during each period, excluding treasury
shares. Net earnings (loss) attributable to common stock represents net
earnings (loss) less preferred stock dividends of $189,000 in 1997, $2,158,000
in 1996 and $2,160,000 in 1995.
Diluted earnings (loss) per share is computed by adjusting the average number
of common shares outstanding for the dilutive effect, if any, of convertible
preferred stock, stock options and warrants. The effect of potentially
dilutive securities is based on earnings (loss) before extraordinary items.
The Company adopted the provisions of Statement No. 128 as of December 31,
1997. As prescribed by Statement No. 128, the Company has restated prior
periods' earnings per share of common stock, including interim earnings per
share of common stock, in the period of adoption.
51
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED):
- -------------------------------------------------------------------------------
The following sets forth the calculation of basic and diluted earnings per
share for income before extraordinary items for the years ended December 31:
1997 1996 1995
------ ------ ------
(In Thousands Except Per Share Amounts)
Income (loss) before extraordinary items $ 3,089 1,139 (17,996)
Less: Preferred stock dividends (189) (2,158) (2,160)
------- ------ -------
Income (loss) before extraordinary items
available to common stockholders $ 2,900 (1,019) (20,156)
------- ------ -------
------- ------ -------
Weighted average common shares
outstanding during the period 33,669 25,062 7,360
Basic earnings (loss) per share
before extraordinary items $ 0.09 (0.04) (2.74)
------- ------ -------
------- ------ -------
Weighted average common shares outstanding
during the period 33,669 25,062 7,360
Add dilutive effects of:
$.75 Convertible preferred stock 326 - -
Employee options 229 - -
Anschutz warrants 737 - -
------- ------ -------
Weighted average common shares outstanding
during the period including the effects
of dilutive securities 34,961 25,062 7,360
------- ------ -------
------- ------ -------
Diluted earnings (loss) per share before
extraordinary items $ 0.08 (0.04) (2.74)
------- ------ -------
------- ------ -------
The following securities were antidilutive in the periods presented:
1997 1996 1995
------ ------ ------
(In Thousands)
Employee options - 81 -
Anschutz warrants - 815 106
JEDI (Anschutz) option - 167 -
$.75 Convertible preferred stock - 2,014 -
Anschutz preferred stock - 1,032 534
----- ----- ----
Total antidilutive potential
common shares - 4,109 640
----- ----- ----
----- ----- ----
RECLASSIFICATIONS - Certain amounts in prior years' financial statements have
been reclassified to conform to the 1997 financial statement presentation.
52
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(2) ACQUISITIONS:
- -------------------------------------------------------------------------------
SAXON PETROLEUM INC.:
During 1995, the Company completed acquisitions totaling $26,807,000. The
most significant of these was the purchase on December 20, 1995 of a 56%
economic (49% voting) interest in Saxon Petroleum Inc. (Saxon) for
approximately $22,000,000. Saxon is a Canadian exploration and production
company with headquarters in Calgary, Alberta and operations concentrated in
western Alberta. In the transaction, Forest received from Saxon 40,800,000
voting common shares, 12,300,000 nonvoting common shares which are
convertible to voting shares at any time, 15,500,000 convertible preferred
shares and warrants to purchase 5,300,000 common shares. In exchange, Forest
transferred to Saxon its preferred shares of Archean Energy, Ltd., issued to
Saxon 1,060,000 Common Shares of Forest and paid Saxon $1,500,000 CDN. The
preferred shares of Archean Energy, Ltd. were recorded at their historical
carrying value of $11,301,000. The Forest Common Shares issued to Saxon were
recorded at their estimated fair value determined by reference to the quoted
market price of the shares immediately preceding the announcement of the
acquisition.
Since Forest has majority voting control over Saxon as a result of the voting
common shares that it owns and proxies that it holds, it has accounted for
Saxon as a consolidated subsidiary from the date of its acquisition. The
Company did not record any production or results of operations of Saxon for
the period from December 20 to December 31, 1995 as the results of operations
for such period were not significant.
The Forest Common Shares held by Saxon were recorded as treasury stock by
Forest at December 31, 1995. In January 1996, Saxon sold these shares in a
public offering of Forest Common Stock and used the proceeds to reduce its
bank debt.
In September 1996, the preferred shares of Archean were redeemed for cash at
their approximate carrying value.
On January 21, 1997 Forest converted its preferred shares of Saxon into
27,192,983 nonvoting common shares. Through December 31, 1997, pursuant to an
equity participation agreement, Forest acquired 5,569,542 voting common shares
and 2,380,608 nonvoting common shares of Saxon in exchange for 196,856 Common
Shares of Forest. Such shares were subsequently sold by Saxon. Also in 1997,
Forest's wholly-owned subsidiary Canadian Forest acquired 993,600 voting
common shares of Saxon in exchange for approximately $497,000 CDN. These
transactions increased Forest's economic interest in Saxon to 65%.
The board of directors of Saxon has created a special committee of independent
directors which has engaged a third party to assess the asset base of Saxon
and to determine strategic alternatives to maximize shareholder value. The
Company anticipates that this assessment may result in a transaction in which
Forest would either sell its entire interest in Saxon or seek to acquire all
or a portion of the minority interest. No assurance can be given as to
whether any such transaction will occur or as to the terms thereof.
CANADIAN FOREST OIL LTD.:
On January 31, 1996 the Company acquired ATCOR Resources Ltd. of Calgary,
Alberta for approximately $136,000,000, including acquisition costs of
approximately $1,000,000. The purchase was funded by the net proceeds of a
Common Stock offering and approximately $8,300,000 drawn under the Company's
bank credit facility. The exploration and production business of ATCOR was
renamed Canadian Forest Oil Ltd. (Canadian Forest). Canadian Forest's
principal reserves and producing properties are located in Alberta and
British Columbia, Canada.
As part of the Canadian Forest acquisition, Forest also acquired ATCOR's
natural gas marketing business which was renamed Producers Marketing Ltd.
(ProMark). Goodwill and other intangibles recorded in the acquisition
included approximately $15,000,000 associated with certain natural gas
marketing contracts, which is being amortized over the average life of the
contracts of 12 years, and approximately $17,000,000 of goodwill associated
with the gas marketing business acquired which is being amortized over 20
years.
53
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(2) ACQUISITIONS (CONTINUED):
- -------------------------------------------------------------------------------
The consolidated balance sheet of Forest includes the accounts of Saxon and
Canadian Forest at December 31, 1997 and 1996. The consolidated statements of
operations include the results of operations of Saxon effective January 1,
1996 and the results of operations of Canadian Forest effective February 1,
1996.
Summarized consolidated financial information for Canadian Forest as of
December 31, 1997 and for the year then ended, and for the period from January
31, 1996 (acquisition date) to December 31, 1996 is as follows:
1997 1996
------ ------
(In Thousands)
SUMMARIZED CONSOLIDATED BALANCE SHEET INFORMATION:
ASSETS
Current assets $ 35,630 29,511
Net property and equipment 117,394 137,278
Goodwill and other intangible
assets, net 26,243 29,439
Other assets 3,320 -
-------- -------
$182,587 196,228
-------- -------
-------- -------
LIABILITIES AND SHAREHOLDERS'
EQUITY
Current liabilities $ 24,029 29,880
Intercompany payable - 32,500
8 3/4% Senior Subordinated Notes 124,690 -
Other liabilities 396 805
Deferred income taxes 36,282 32,912
Shareholders' equity (deficit) (2,810) 100,131
-------- -------
$182,587 196,228
-------- -------
-------- -------
SUMMARIZED CONSOLIDATED STATEMENTS
OF OPERATIONS:
Revenue $214,045 224,757
-------- -------
-------- -------
Earnings (loss) before income taxes $ (3,321) 9,685
-------- -------
-------- -------
Net earnings (loss) $ (4,952) 4,739
-------- -------
-------- -------
The Company prepares ceiling test computations on a country-by-country basis
and, accordingly, has not prepared such computation for Canadian Forest on a
stand-alone basis. The Company has not presented separate financial
statements and other disclosures concerning Canadian Forest because management
has determined that such information is not material to the holders of the 8
3/4% Notes.
LOUISIANA ACQUISITION:
On February 3, 1998 the Company purchased 13 oil and gas properties located
onshore Louisiana (the Louisiana Acquisition) for total consideration of
approximately $230,776,000. The consideration consisted of approximately
$216,557,000 in cash, funded primarily from the Company's bank credit
facility, and from the issuance of $75,000,000 principal amount of 8 3/4%
Notes and 1,000,000 shares of the Company's Common Stock.
54
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(2) ACQUISITIONS (CONTINUED):
- -------------------------------------------------------------------------------
The following unaudited pro forma consolidated statement of operations
information assumes that the Louisiana Acquisition occurred as of January 1,
1997:
Pro Forma Year Ended
December 31, 1997
--------------------
(In Thousands Except
Per Share Amounts)
Revenue:
Marketing and processing $184,399
Oil and gas sales 185,682
--------
Total revenue $370,081
--------
--------
Earnings before income taxes
and extraordinary item $ 997
--------
--------
Net loss $(14,655)
--------
--------
Basic loss per share $ (.43)
--------
--------
Diluted loss per share $ (.41)
--------
--------
(3) ANSCHUTZ AND JEDI TRANSACTIONS:
- -------------------------------------------------------------------------------
During 1995 and 1996, the Company consummated transactions with The Anschutz
Corporation (Anschutz) and with Joint Energy Development Investments Limited
Partnership (JEDI), a Delaware limited partnership the general partner of
which is an affiliate of Enron Corp. (Enron).
Pursuant to a purchase agreement between the Company and Anschutz, Anschutz
purchased 3,760,000 shares of the Company's Common Stock and 620,000 shares
of a new series of preferred stock which were convertible into 1,240,000
shares of Common Stock for a total consideration of $45,000,000. The
Preferred Stock had a liquidation preference of $18.00 per share and received
dividends ratably with the Common Stock. In addition, Anschutz received a
warrant that entitled it to purchase 3,888,888 shares of the Company's Common
Stock for $10.50 per share (the A Warrant). The A Warrant was scheduled to
expire July 27, 1998.
The Anschutz investment was made in two closings. At the first closing,
which occurred on May 19, 1995, Anschutz loaned the Company $9,900,000 at
8% per annum. The loan was nonrecourse to the Company and was secured by oil
and gas properties owned by the Company, the preferred stock of Archean Energy
Ltd., and a cash collateral account with an initial balance of $2,000,000. At
the second closing, which occurred in July 1995, Anschutz converted the loan
into 1,100,000 shares of Common Stock and the shares issued were recorded at
the carrying amount of the loan ($9,900,000). At the second closing, Anschutz
purchased an additional 2,660,000 shares of Common Stock, the convertible
preferred stock and the A Warrant for $35,100,000. The total proceeds
received by the Company at the second closing were allocated based on the
relative fair market values of the Common Stock ($18,272,000), convertible
preferred stock ($8,518,000) and the A Warrant ($8,310,000) issued. The
Company also entered into a shareholders agreement with Anschutz pursuant to
which Anschutz agreed to certain voting, acquisition, and transfer limitations
regarding its shares of Common Stock for five years after the second closing.
55
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(3) ANSCHUTZ AND JEDI TRANSACTIONS:
- -------------------------------------------------------------------------------
At the second closing on July 27, 1995, Forest and JEDI restructured JEDI's
existing loan which had a principal balance of approximately $62,368,000
before unamortized discount of $4,984,000. As a part of the restructuring,
the existing JEDI loan balance was divided into two tranches: a $40,000,000
tranche, which bore interest at the rate of 12.5% per annum and was due and
payable in full on December 31, 2000; and an approximately $22,400,000
tranche, which did not bear interest and was due and payable in full on
December 31, 2002. JEDI also relinquished the net profits interest that it
held in certain properties of the Company. In consideration, JEDI received a
warrant (the B Warrant) that entitled it to purchase 2,250,000 shares of the
Company's Common Stock for $10.00 per share. The B Warrant was recorded at
its estimated fair value. The fair value of the B Warrant was estimated to
be approximately $12,100,000, representing the amount determined using the
Black-Scholes Option Pricing Model, based on the market value of the stock at
the date of the transaction, less a discount of 10% to reflect the size of
the block of shares to be issued and the estimated brokerage fees on the
ultimate disposition of the shares.
Also at the second closing, JEDI granted an option to Anschutz (the Anschutz
Option), pursuant to which Anschutz was entitled to purchase from JEDI up to
2,250,000 shares of the Company's Common Stock at a purchase price per share
equal to the lesser of (a) $10.00 plus 18% per annum from July 27, 1995 to
the date of exercise of the option, or (b) $15.50. The Anschutz Option was
scheduled to terminate on July 27, 1998. JEDI was to satisfy its obligations
under the Anschutz Option by exercising the B Warrant. The Company also
agreed to use the proceeds from the exercise of the A Warrant to pay
principal and interest on the $40,000,000 tranche of the JEDI loan.
As a result of the loan restructuring and the issuance of the B Warrant, the
Company reduced the recorded amount of the related liability to approximately
$45,493,000. No gain or loss was recorded on the loan restructuring since
the estimated fair value of the restructured loan and the B Warrant was
approximately equal to the original loan balance.
In December 1995, JEDI exchanged the $22,400,000 tranche and the B Warrant
for 1,680,000 shares of Common Stock (the JEDI Exchange). The fair value of
the 1,680,000 shares of Common Stock was estimated to be $15,400,000 based on
the quoted market price of the Common Stock at the date of the transaction,
less a discount of 35% to reflect the shareholder agreement with JEDI that
limited JEDI's ability to vote the shares or to transfer the shares before
July 27, 1998, the size of the block of stock and the estimated brokerage
fees on the ultimate disposition of the shares. No gain or loss was recorded
on the exchange since the estimated fair value of the Common Stock issued
less the estimated fair value of the B Warrant reacquired was approximately
equal to the carrying amount of the $22,400,000 tranche.
Pursuant to the JEDI Exchange, the Company assumed JEDI's obligations under
the Anschutz Option. Under the Anschutz Option, the Company was then
obligated to issue shares directly to Anschutz that previously would have
been issued to JEDI pursuant to the B Warrant.
On August 1, 1996, The Anschutz Corporation exercised the Anschutz Option to
purchase 2,250,000 shares of Common Stock for $26,200,000 or approximately
$11.64 per share. Proceeds received by Forest were used primarily to fund a
portion of 1996 capital expenditures.
On November 5, 1996, the Company exchanged 2,000,000 shares of Common Stock
plus approximately $13,500,000 cash to extinguish approximately $43,000,000
of nonrecourse secured debt then owed to JEDI. In connection with this
transaction, Anschutz acquired 1,628,888 shares of Common Stock by exercising
a portion of the A Warrant to purchase 388,888 shares of Common Stock at
$10.50 per share and by converting 620,000 shares of Forest's Second Series
Preferred Stock into 1,240,000 shares of Common Stock. The term of the
remaining 3,500,000 warrants held by Anschutz was extended to July 27, 1999.
The fair value of the shares of Common Stock issued to JEDI was estimated
based on the quoted market price of the Common Stock at the date of the
transaction, less a discount of 7-1/2% to reflect the lock-up agreement with
JEDI that limited JEDI's ability to transfer the shares before May 31, 1997,
the size of the block of shares to be issued and the estimated brokerage fees
on the
56
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(3) ANSCHUTZ AND JEDI TRANSACTIONS:
- -------------------------------------------------------------------------------
ultimate disposition of the shares. The fair value of the Common Stock
issued and the cash paid to JEDI, including related expenses of the
transaction, was less than the carrying amount of the debt extinguished.
Accordingly, the Company recorded an extraordinary gain on extinguishment of
debt in the fourth quarter of 1996 of approximately $2,166,000.
On August 28, 1997 Anschutz acquired 3,500,000 shares of Common Stock through
the exercise of the A Warrant for $8.60 per share resulting in cash proceeds
to Forest of $30,100,000. The original exercise price was $10.50 per share.
The reduction in the exercise price offered to Anschutz reflected an
approximate 10% present value discount computed to the warrants' expiration
date of july 27, 1999. Proceeds from the exercise were used to reduce
borrowings under the Company's bank credit facilities.
(4) INVESTMENT IN AFFILIATE:
- -------------------------------------------------------------------------------
In 1992, the Company sold its Canadian assets and related operations to
CanEagle Resources Corporation (CanEagle). In the transaction, the Company
received cash, net of expenses, and provided financing. On June 24, 1994
CanEagle sold a significant portion of its oil and gas properties to a third
party. In conjunction with this transaction, the Company received cash and
exchanged its investment in CanEagle for shares of preferred stock of a newly
formed entity, Archean energy, Ltd. (Archean). The Company accounted for the
proceeds from the 1994 transaction as a reduction in the carrying value of
its investment in CanEagle. The preferred shares of Archean were recorded at
an amount equal to the remaining carrying value of the Company's investment
in CanEagle.
The Company accounted for its investment in Archean (and CanEagle prior to
June 24, 1994) in a manner analagous to equity accounting. Losses were
recognized to the extent that losses were attributable to the Company's
interest. Earnings were recognized only if realization was assured. Under
this method, no earnings or losses were recognized in 1996 or 1995.
In December 1995, in connection with the Saxon acquisition, the Company
transferred its Archean preferred stock to Saxon and the Company continued to
account for the investment in Archean at its historical carrying value. In
September 1996, the preferred shares of Archean were redeemed for cash at
their approximate carrying value.
(5) LONG-TERM DEBT:
- -------------------------------------------------------------------------------
Long-term debt at December 31 consists of the following:
1997 1996
------ ------
(In Thousands)
U.S. Credit Facility $ 85,550 26,400
Canadian Credit Facility - 32,500
Saxon Credit Facility 25,840 -
Production payment obligation 10,004 12,596
11 1/4% Senior Subordinated Notes 8,676 99,421
8 3/4% Senior Subordinated Notes 124,690 -
-------- ------
254,760 170,917
Less current portion - (2,058)
-------- ------
LONG-TERM DEBT $254,760 168,859
-------- ------
-------- ------
57
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(5) LONG-TERM DEBT (CONTINUED):
- -------------------------------------------------------------------------------
U.S. AND CANADIAN FOREST CREDIT FACILITIES: At December 31, 1997 the Company
and its subsidiaries, Canadian Forest and ProMark, had a $250,000,000 global
credit facility (the Global Credit Facility) which provided for a global
borrowing base of $130,000,000 through a syndicate of banks led by the Chase
Manhattan Bank and the Chase Manhattan Bank of Canada. The borrowing base is
subject to semi-annual redeterminations. Under the Global Credit Facility,
the Company can allocate the global borrowing base between the United States
and Canada, subject to specified limitations. Funds borrowed under
the Global Credit Facility can be used for general corporate purposes. Under
the terms of the Global Credit Facility, the Company, Canadian Forest and
ProMark are subject to certain covenants and financial tests, including
restrictions or requirements with respect to working capital, cash flow,
additional debt, liens, asset sales, investments, mergers, cash dividends and
reporting responsibilities.
The Global Credit Facility is secured by a lien on, and a security interest
in, a portion of the Company's U.S. proved oil and gas properties, related
assets, pledges of accounts receivable and a pledge of 66% of the capital
stock of Canadian Forest. The Global Credit Facility is also indirectly
secured by substantially all of the assets of Canadian Forest.
On February 3, 1998, the Company amended the Global Credit Facility. the
primary purpose of the amendment was to increase the credit facility to
$300,000,000 and the borrowing base to $260,000,000 in order to finance the
Louisiana Acquisition. Under the amended Global Credit Facility, the maximum
credit facility allocations in the United States and Canada are $275,000,000
and $25,000,000, respectively. The borrowing base is currently allocated
$250,000,000 to the United States and $10,000,000 to Canada.
At December 31, 1997 the outstanding U.S. balance under the Global Credit
Facility was $85,550,000 with a weighted average interest rate of 7.42% per
annum and there was no outstanding Canadian balance under the Global Credit
Facility. The Company had also used the Global Credit Facility for a Canadian
letter of credit in the amount of $4,522,000 CDN.
SAXON CREDIT FACILITY:
Saxon has a credit facility with a borrowing base of $39,800,000 CDN. The
loan is subject to semi-annual review and has demand features; however,
repayments are not required provided that borrowings are not in excess of the
borrowing base and Saxon complies with other existing covenants. At December
31, 1997 the outstanding balance under this facility was $36,957,000 CDN.
PRODUCTION PAYMENT OBLIGATION:
The dollar-denominated production payment was entered into in 1992 to finance
property acquisitions. The original amount of the dollar-denominated
production payment was $37,550,000, which was recorded as a liability of
$28,805,000 after a discount to reflect a market rate of interest of 15.5%.
At December 31, 1997 the remaining principal amount was $14,895,000 and the
recorded liability was $10,004,000. Under the terms of this production
payment, the Company must make a monthly cash payment which is the greater of
a base amount or 85% of net proceeds from the subject properties located in
the United States, as defined, except that the amount required to be paid in
any given month shall not exceed 100% of the net proceeds from the subject
properties. The Company
58
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(5) LONG-TERM DEBT (CONTINUED):
- -------------------------------------------------------------------------------
retains a management fee equal to 10% of sales from the properties, which is
deducted in the calculation of net proceeds. The Company's estimate as of
December 31, 1997, based on expected production and prices, budgeted capital
expenditure levels and expected discount amortization, is that projected
payments will decrease the recorded liability by approximately $195,000 in
1998, $80,000 in 1999, $1,055,000 in 2000, $1,028,000 in 2001 and
$1,418,000 in 2002. Properties to which approximately 3% of the Company's
estimated proved reserves are attributable, on an MCFE basis, are dedicated
to this production payment financing.
11-1/4% SENIOR SUBORDINATED NOTES:
On September 8, 1993 the Company completed a public offering of $100,000,000
aggregate principal amount of 11-1/4% Senior Subordinated Notes due September
1, 2003 (the 11-1/4% Notes). On September 29, 1997, pursuant to a tender offer,
$90,233,000 of the Company's outstanding $100,000,000 aggregate principal amount
of 11-1/4% Notes was tendered by the holders. The purchase price for each
$1,000 principal amount of 11-1/4% Notes validly tendered and accepted was
$1,096.96. On October 17, 1997 an additional $1,091,000 aggregate principal
amount of 11-1/4% Notes was tendered at a purchase price of $1,090.00 for each
$1,000.00 principal amount. As a result of these purchases, Forest recorded an
extraordinary loss of approximately $12,359,000 relating to the excess of the
tender price over the carrying amount of the 11-1/4% Notes, net of related
unamortized debt issuance costs and original issue discount. The 11-1/4%
Notes are callable on or after September 1, 1998 at 105.688% of principal
amount.
8-3/4% SENIOR SUBORDINATED NOTES:
On September 29, 1997 Canadian Forest completed an offering of $125,000,000
of 8-3/4% Senior Subordinated Notes due 2007 (the 8-3/4% Notes), which were
sold at 99.745% of par and guaranteed on a senior subordinated basis by the
Company. A portion of the proceeds was used to fund the tender offer
described above, a portion was used to repay the outstanding balance under
the Canadian Credit Facility and the remainder was used for working capital
and to fund capital expenditures.
The Company is required to recognize foreign currency translation gains or
losses related to the 8-3/4% Notes 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.
On February 2, 1998 Canadian Forest issued $75,000,000 principal amount of
8-3/4% Notes, an add-on to the Company's issue of 8-3/4% Notes that were
issued in September 1997. The Company received net proceeds of approximately
$75,000,000 which were used to provide funds for the Louisiana Acquisition.
(6) DEFERRED REVENUE:
- -------------------------------------------------------------------------------
From 1991 to 1994, the Company sold volumetric production payments to Enron
to fund capital expenditures and property acquisitions.
On June 30, 1997 the Company purchased from Enron the obligation related to
its last remaining volumetric production payment. The purchase price of
approximately $6,832,000 plus expenses was funded by advances under the
Company's Credit Facility.
59
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(6) DEFERRED REVENUE (CONTINUED):
- -------------------------------------------------------------------------------
Amounts received under the production payments were recorded as deferred
revenue. Volumes associated with amortization of deferred revenue for the
years ended December 31, 1997, 1996 and 1995 were as follows:
Net sales volumes
attributable to production
Volumes delivered (1) Payment deliveries (2)
----------------------- --------------------------
Natural Gas Oil Natural Gas oil
(MMCF) (MBBLS) (MMCF) (MBBLS)
----------- ------- ----------- -------
1997 951 - 801 -
1996 3,721 87 3,168 74
1995 11,045 173 9,120 145
(1) Amounts settled in cash in lieu of volumes were $700,000, $1,641,000
and $2,433,000 for the years ended December 31, 1997, 1996, and 1995,
respectively.
(2) Represents volumes required to be delivered to Enron affiliates net of
estimated royalty volumes.
(7) INCOME TAXES:
The income tax expense (benefit) is different from amounts computed by
applying the statutory Federal income tax rate for the following reasons:
1997 1996 1995
---- ---- ----
(In Thousands)
Tax expense (benefit) at 35% of income (loss)
before income taxes and extraordinary item $ 2,234 2,300 (6,367)
Change in the valuation allowance for deferred
tax assets attributable to income (loss) before
income taxes and extraordinary item (1,819) (367) 5,732
Canadian earnings taxed at a higher effective rate 85 1,068 -
Canadian Crown payments (net of Alberta Royalty
Tax Credit) not deductible for tax purposes 3,181 2,799 -
Canadian resource allowance (3,995) (3,005) -
Non-deductible depletion and amortization 1,934 1,694 -
Expiration of tax carryforwards 1,041 643 535
Unrealized foreign exchange losses and other 632 319 93
------- ------ ------
Total income tax expense (benefit) $ 3,293 5,451 (7)
------- ------ ------
------- ------ ------
Deferred income taxes generally result from recognizing income and expenses at
different times for financial and tax reporting. In the U.S., the largest
current difference is the tax effect of the capitalization of certain
development, exploration and other costs under the full cost method of
accounting, recording proceeds from the sale of properties in the full cost
pool, and the provision for impairment of oil and gas properties for financial
accounting purposes. In Canada, differences result in part from accelerated
cost recovery of oil and gas capital expenditures for tax purposes.
60
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(7) INCOME TAXES (CONTINUED):
- -------------------------------------------------------------------------------
The components of the net deferred tax liability at December 31, 1997 and
1996 are as follows:
1997 1996
---- ----
(In Thousands)
Deferred tax assets:
Allowance for doubtful accounts $ 266 296
Accrual for retirement benefits 865 1,128
Accrual for medical benefits 2,134 2,220
Accrual for sales recorded on the entitlement method 1,538 1,499
Accrual for interest rate swaps 169 509
Investment in subsidiaries 4,971 -
Deferred revenue 938 -
Net operating loss carryforward 41,329 51,393
Depletion carryforward 6,958 6,958
Investment tax credit carryforward 1,539 2,576
Alternative minimum tax credit carryforward 2,201 2,187
Unrealized foreign exchange losses 1,402 -
Other 390 613
-------- --------
Total gross deferred tax assets 64,700 69,379
Less valuation allowance (48,417) (45,910)
-------- --------
Net deferred tax assets 16,283 23,469
Deferred tax liabilities:
Property and equipment (45,612) (51,129)
Deferred income on long term contracts (5,243) (6,014)
Other (195) (42)
-------- --------
Total gross deferred tax liabilities (51,050) (57,185)
-------- --------
Net deferred tax liability $(34,767) (33,716)
-------- --------
-------- --------
The net change in the valuation allowance for the years ended December 31,
1997 and 1996 was an increase of $2,507,000 and $786,000, respectively, which
resulted from:
1997 1996
---- ----
(In Thousands)
Increase (decrease) in the valuation allowance for deferred
tax assets attributable to income (loss) before income
taxes and extraordinary item $(1,819) 1,544
Increase (decrease) in the valuation allowance attributable
to the extraordinary loss (gain) 4,326 (758)
-------- -------
Net increase in the valuation allowance $ 2,507 786
-------- -------
-------- -------
61
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(7) INCOME TAXES (CONTINUED):
- -------------------------------------------------------------------------------
The Alternative Minimum Tax (AMT) credit carryforward available to reduce
future U.S. Federal regular taxes aggregated $2,201,000 at December 31, 1997.
This amount may be carried forward indefinitely. U.S. Federal regular and
AMT net operating loss carryforwards at December 31, 1997 were $111,473,000
and $106,506,000, respectively, and will expire in the years indicated below:
Regular AMT
------- -------
(In Thousands)
2000 $ 3,590 3,987
2005 8,307 -
2008 28,999 31,799
2009 22,817 22,964
2010 45,737 46,059
2011 268 -
2012 1,755 1,697
-------- -------
$111,473 106,506
-------- -------
-------- -------
AMT net operating loss carryforwards can be used to offset 90% of AMT income
in future years.
Investment tax credit carryforwards available to reduce future U.S. Federal
income taxes aggregated $1,539,000 at December 31, 1997 and expire at
various dates through the year 2001. Percentage depletion carryforwards
available to reduce future U.S. Federal taxable income aggregated $19,879,000
at December 31, 1997. This amount may be carried forward indefinitely.
Canadian net operating losses available to reduce future Canadian Federal
income taxes were $5,173,000 ($7,399,000 CDN) at December 31, 1997 and will
expire in the years indicated below:
(In Thousands)
1998 $ 4,734
2000 234
2003 205
----------
$ 5,173
----------
----------
Canadian tax pools relating to the exploration, development and production of
oil and natural gas which are available to reduce future Canadian Federal
income taxes aggregated approximately $52,783,000 ($75,491,000 CDN) for
Canadian Forest and $57,824,000 ($82,700,000 CDN) for Saxon at December
31, 1997. These tax pool balances are deductible on a declining balance
basis ranging from 10% to 100% of the balance annually. The amounts may be
carried forward indefinitely.
The availability of some of these U.S. Federal tax attributes to reduce
current and future U.S. taxable income of the Company is subject to various
limitations under the Internal Revenue Code. In particular, the Company's
ability to utilize such tax attributes could be limited due to the occurrence
of an "ownership change" within the meaning of Section 382 of the Internal
Revenue Code resulting from the Anschutz transaction in 1995 and the public
stock issuance in 1996. Under the general provisions of Section 382 of the
Code, the Company's net operating loss carryforwards will be subject to an
annual limitation as to their use of approximately $5,700,000. Even though
the Company is limited in its ability to use the net operating loss
carryovers under these provisions of Section 382, it may be entitled to use
these net operating loss carryovers to offset (a) gains recognized in the
five years following the ownership change on the disposition of certain
assets, to the extent that the value of the assets disposed of exceeds their
tax basis on the date of the ownership change or (b) any item of income which
is properly taken into account in the five years following the ownership
change but which is attributable to periods before the ownership change
(built-in gain). The ability of the Company to use these net operating loss
carryovers to offset built-in gain first requires that the Company have total
built-in gains at the time of the ownership change which are greater than a
threshold amount. In addition, the use of these net operating loss
carryforwards to offset built-in gain cannot exceed the amount of the total
built-in gain. The Company has not finalized its calculation of the amount
of built-in gains at
62
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(7) INCOME TAXES (CONTINUED):
- -------------------------------------------------------------------------------
the date of the ownership change, but estimates that its ability to fully
utilize its net operating loss carryforwards may be limited by these provisions.
Due to limitations in the Internal Revenue Code, other than the Section 382
limitations discussed above, the Company believes it is unlikely that it will
be able to use any significant portion of its investment tax credit
carryforwards before they expire.
(8) PREFERRED STOCK:
- -------------------------------------------------------------------------------
$.75 CONVERTIBLE PREFERRED STOCK: The Company had 10,000,000 shares of $.75
Convertible Preferred Stock authorized, par value $.01 per share, of which
there were 2,877,673 shares outstanding at December 31, 1996 with an aggregate
liquidation preference of $28,776,730.
The Company called for redemption on February 7, 1997 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.
SECOND SERIES PREFERRED STOCK: At December 31, 1995 the Company had 620,000
shares of Second Series Preferred Stock authorized, par value $.01 per share,
of which there were 620,000 shares outstanding with an aggregate liquidation
preference of $11,160,000. On November 5, 1996 all 620,000 shares of the
Second Series Preferred Stock were converted into 1,240,000 shares of Common
Stock.
(9) COMMON STOCK:
- -------------------------------------------------------------------------------
COMMON STOCK: The Company has 200,000,000 shares of Common Stock authorized,
par value $.10 per share. On January 5, 1996 a 5-to-1 reverse stock split
was approved by the Company's shareholders. The reverse split became
effective on January 8, 1996. Unless otherwise indicated, all share amounts
have been adjusted to give effect to the 5-to-1 reverse stock split.
In March 1997 and May 1997, pursuant to its Equity Participation Agreement
with Saxon, Forest exercised its right to purchase from the treasury of Saxon
7,950,150 shares (2,380,608 non-voting) of common stock. In consideration,
Forest issued 196,856 shares of Forest Common Stock to Saxon valued at $14.31
per share. The shares issued by Forest to Saxon were classified as treasury
shares prior to their sale by Saxon in October 1997.
On January 31, 1996 13,200,000 shares of Common Stock were sold for $11.00
per share in a public offering. Of this amount 1,060,000 shares were sold by
Saxon and 12,140,000 were sold by Forest. The net proceeds to Forest and
Saxon from the issuance of shares totaled approximately $136,000,000 after
deducting issuance costs and underwriting fees.
In October 1993, the Board of Directors adopted a shareholders' rights plan
(the Plan) and entered into the Rights Agreement. The Company paid a
dividend distribution of one Preferred Share Purchase Right (the Rights) on
each outstanding share of the Company's Common Stock. The Rights are
exercisable only if a person or group acquires
63
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(9) COMMON STOCK (CONTINUED):
- -------------------------------------------------------------------------------
20% or more of the Company's Common Stock or announces a tender offer which
would result in ownership by a person or group of 20% or more of the Common
Stock. Each right initially entitles each shareholder to buy 1/100th of a
share of a new series of Preferred Stock at an exercise price of $30.00,
subject to adjustment upon certain occurrences. Each 1/100th of a share of
such new Preferred Stock that can be purchased upon exercise of a Right has
economic terms designed to approximate the value of one share of Common
Stock. The Rights will expire on October 29, 2003, unless extended or
terminated earlier. In connection with the Anschutz transaction, the Company
amended the Rights Agreement to exempt from the provisions of the Rights
Agreement shares of Common Stock acquired by Anschutz and JEDI in the
Anschutz and JEDI transactions, including shares later acquired pursuant to
the conversion of the Second Series Preferred Stock and the exercise of the A
Warrant and the Anschutz Option. The amendment to the Rights Agreement did
not exempt other shares of Common Stock acquired by Anschutz or JEDI from the
provisions of the Rights Agreement.
WARRANTS:
At December 31, 1995 the Company had outstanding 1,244,715 warrants to purchase
shares of its Common Stock (the Public Warrants). Each Public Warrant entitled
the holder to purchase one-fifth of a share of Common Stock at a price of $3.00
and was noncallable. During 1996, 112,185 warrants were exercised to purchase
22,437 shares of Common Stock. On October 1, 1996 the remaining Public Warrants
expired.
In December 1995, the Company assumed JEDI's obligations under the Anschutz
Option. On August 1, 1996 Anschutz exercised the Anschutz Option for
$26,200,000 or approximately $11.64 per share and Anschutz received 2,250,000
shares of Common Stock.
At December 31, 1996 the Company had outstanding the A Warrant that was held
by Anschutz. At that date, the A Warrant entitled the holder to purchase
3,500,000 shares of Common Stock at a price of $10.50 per share. The Warrant
was scheduled to expire on July 27, 1999. On November 5, 1996 Anschutz
exercised a portion of the A Warrant and purchased 388,888 shares of Common
Stock at $10.50 per share. On August 28, 1997 Anschutz acquired 3,500,000
shares of Common Stock through the exercise of the A Warrant for $8.60 per
share resulting in cash proceeds to Forest of $30,100,000. The reduction in
the exercise price offered to Anschutz reflects an approximate 10% present
value discount computed to the warrants' expiration date of July 27, 1999.
Proceeds from the exercise were used to reduce borrowings under the Company's
bank credit facilities.
At December 31, 1997 the Company had no outstanding warrants.
STOCK INCENTIVE PLAN:
In November 1997, three executive officers of the Company received conditional
restricted stock awards in lieu of stock option grants. The restricted stock
awarded is subject to certain conditions and is subject to a two-year
restriction on transfer. If prior to January 1, 1999 the closing price of
the Company's Common Stock during any twenty-consecutive-trading-day period
as reported on the New York Stock Exchange is at least $22.00 per share, a
total of 230,000 shares will be earned under the conditions of the restricted
stock awards. Additional shares will be earned for each $1.00 increase in
such average price to a maximum of 850,000 shares if the average price is
$30.00 or higher.
During 1997, the Company issued 17,617 shares of restricted Common Stock to
officers and employees as a portion of the bonuses earned for the year ended
December 31, 1996. The shares vested immediately upon issuance, but are
subject to a two-year restriction on transfer.
STOCK OPTIONS:
In March 1992, the Company adopted the 1992 Stock Option Plan under which
non-qualified stock options may be granted to key employees and non-employee
directors. The aggregate number of shares of Common Stock which the Company
may issue under options granted pursuant to this plan may not exceed 10% of
the total number of shares outstanding or issuable at the date of grant
pursuant to outstanding rights, warrants, convertible or exchangeable
securities or other options. The exercise price of an option may not be less
than 85% of the fair market value of one share of the Company's Common Stock
on the date of grant. The options vest 20% on the date of grant and an
additional 20% on each grant anniversary date thereafter.
64
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(9) COMMON STOCK (CONTINUED):
- -------------------------------------------------------------------------------
The following table summarizes the activity in the Company's stock-based
compensation plan for the years ended December 31, 1995, 1996 and 1997:
Weighted
Average Number of
Number of Exercise Shares
Shares Price Exercisable
--------- -------- -----------
Outstanding at December 31, 1995 628,000 $20.46 461,200
Granted at fair value 1,383,900 12.74
Exercised (35,120) 11.42
Cancelled (515,200) 20.47
--------- ------
Outstanding at December 31, 1996 1,461,580 13.37 362,460
GRANTED AT FAIR VALUE 433,000 16.98
EXERCISED (43,720) 12.09
CANCELLED (61,500) 12.79
--------- ------
OUTSTANDING AT DECEMBER 31, 1997 1,789,360 $14.29 669,620
--------- ------
--------- ------
The following table summarizes information about options outstanding at
December 31, 1997:
Options Outstanding Options Exercisable
-------------------------------- -------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Range of Number of Contractual Exercise Number of Exercise
Exercise Price Shares Life Price Shares Price
-------------- --------- ----------- -------- --------- --------
$11.25 483,660 8.10 $11.25 169,620 $11.25
$12.38-13.94 124,000 8.83 12.64 40,000 12.64
$14.00 627,200 8.84 14.00 250,400 14.00
$14.25-17.50 496,500 9.07 16.79 151,600 16.17
$25.00 58,000 4.75 25.00 58,000 25.00
----------- --------- ---- ------ ------- -----
$11.25-25.00 1,789,360 8.57 $14.29 669,620 $14.67
----------- --------- ---- ------ ------- -----
----------- --------- ---- ------ ------- -----
The Company applies APB Opinion 25 and related Interpretations in accounting
for its plans. Accordingly, no compensation cost is recognized for options
granted at a price equal to the fair market value of the common stock. Had
compensation cost for the Company's stock-based compensation plan been
determined using the fair value of the options at the grant date, the
Company's net loss for the years ended December 31, 1997 and 1996 would have
been $11,864,000 and $2,230,000, respectively, and the basic loss per share
would have been $.36 and less than $.01 per share, respectively. There were
no stock options granted in 1995; accordingly, no compensation cost would have
been recognized in that year.
The fair value of each option granted in 1997 and 1996 was estimated using
the Black-Scholes option pricing model. The following assumptions were used
in 1997: expected option life of 5 years; risk free interest rates ranging
from 5.752% to 6.839%; estimated volatility of 55.74%; and dividend yield of
zero percent. The weighted average fair market value of options granted
during 1997 was estimated to be $9.20 per share based on these assumptions.
The following assumptions were used in 1996: expected option life of 5
years; risk free interest rates ranging from 5.261% to 6.022%; estimated
volatility of 59.95%; and dividend yield of zero percent. The weighted
average fair market value of options granted during 1996 was estimated to be
$7.22 per share based on these assumptions.
65
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(10) EMPLOYEE BENEFITS
- -------------------------------------------------------------------------------
PENSION PLANS:
The Company has a qualified defined benefit pension plan which covers its United
States employees (Pension Plan). The Pension Plan has been curtailed and all
benefit accruals were suspended effective May 31, 1991.
The benefits under the Pension Plan are based on years of service and the
employee's average compensation during the highest consecutive sixty-month
period in the fifteen years prior to retirement. No contribution was made to
the Plan in 1997, 1996 or 1995.
The following table sets forth the Pension Plan's funded status and amounts
recognized in the Company's consolidated financial statements at December 31:
1997 1996
---- ----
(In Thousands)
Actuarial present value of accumulated benefit obligation
(all benefits are vested) $(26,700) (25,959)
-------- -------
-------- -------
Projected benefit obligation for service rendered to date $(26,700) (25,959)
Plan assets at fair market value, consisting primarily of
listed stocks, bonds and other fixed income obligations 24,808 24,897
-------- -------
Unfunded pension liability (1,892) (1,062)
Unrecognized net loss from past experience different from
that assumed and effects of changes in assumptions 3,051 2,012
-------- -------
Pension asset recognized in the balance sheet $ 1,159 950
-------- -------
-------- -------
For 1997, the discount rate used in determining the actuarial present value
of the projected benefit obligation was 7.25% and the expected long-term rate
of return on assets was 9%. For 1996, the discount rate used in determining
the actuarial present value of the projected benefit obligation was 7.75% and
the expected long-term rate of return on assets was 9%. For 1995 the
discount rate used in determining the actuarial present value of the
projected benefit obligation was 7.25% and the expected long-term rate of
return on assets was 9%.
The components of net pension expense (benefit) for the years ended December
31, 1997, 1996 and 1995 are as follows:
1997 1996 1995
---- ---- ----
(In Thousands)
Net pension expense (benefit) included the
following components:
Interest cost on projected benefit obligation $ 1,931 1,926 2,049
Actual return on plan assets (2,386) (3,056) (3,243)
Net amortization and deferral 247 1,098 1,234
------- ------ ------
Net pension expense (benefit) $ (208) (32) 40
------- ------ ------
------- ------ ------
66
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(10) EMPLOYEE BENEFITS (CONTINUED):
- -------------------------------------------------------------------------------
The Company has a non-qualified unfunded supplementary retirement plan that
provides certain officers with defined retirement benefits in excess of
qualified plan limits imposed by Federal tax law. Benefit accruals under this
plan were suspended effective May 31, 1991 in connection with suspension of
benefit accruals under the Pension Plan. At December 31, 1997 the projected
benefit obligation under this plan totaled $618,000, which amount is included in
other liabilities in the accompanying balance sheet. The projected benefit
obligation is determined using the same discount rate as is used for
calculations for the Pension Plan.
As a result of suspension of benefit accruals under the Pension Plan and the
supplementary retirement plan, the Company records as a liability the unfunded
pension liability attributable to these plans. Changes in the minimum unfunded
pension liability are recorded as adjustments to capital surplus.
Canadian Forest's employees are members of a non-contributory defined benefit
pension plan (Canadian Pension Plan). The benefits under the Canadian Pension
Plan are based on years of service, the employee's average annual compensation
during the highest consecutive sixty month period of pensionable service and the
employee's age at retirement. Canadian Forest's contribution to the Canadian
Pension Plan was $47,000 in 1996. No contribution was made to the Canadian
Pension Plan in 1997.
The following table sets forth the Canadian Pension Plan's funded status and
amounts recognized in the Company's consolidated financial statements at
December 31:
1997 1996
---- ----
(In Thousands)
Actuarial present value of accumulated benefit obligation
(all benefits are vested) $(4,362) (4,119)
------- ------
------- ------
Projected benefit obligation for service rendered to date $(4,362) (4,119)
Plan assets at fair market value, consisting primarily of
listed stocks, bonds and other fixed income obligations 5,171 4,922
------- ------
Pension surplus 809 803
Unrecognized net gain from past experience different from
that assumed and effects of changes in assumptions (983) (915)
------- ------
Pension liability recognized in the balance sheet $ (174) (112)
------- ------
------- ------
For 1997 and 1996, the discount rate used in determining the actuarial
present value of the projected benefit obligation was 7% and the expected
long-term rate of return on assets was 7%.
67
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(10) EMPLOYEE BENEFITS (CONTINUED):
- -------------------------------------------------------------------------------
The components of net pension expense for the year ended December 31 are as
follows:
1997 1996
---- ----
(In Thousands)
Net pension expense included the
following components:
Interest cost on projected benefit obligation $ 465 456
Actual return on plan assets (325) (310)
Net amortization and deferral (51) (69)
----- ----
Net pension expense $ 89 77
----- ----
----- ----
RETIREMENT SAVINGS PLANS:
The Company sponsors a qualified tax deferred savings plan in accordance with
the provisions of Section 401(k) of the Internal Revenue Code for its U.S.
employees. Employees may defer up to 10% of their compensation, subject to
certain limitations. The Company matches the employee contributions up to 5%
of employee compensation. In the first six months of 1995, Company
contributions were made using treasury stock. In the last six months of 1995
and in the first nine months of 1996, Company contributions were made by
issuing authorized but unissued shares of Common Stock. In the last three
months of 1996 and all of 1997, Company contributions were made in cash. The
expense associated with the Company's contribution was $482,000 in 1997,
$399,000 in 1996 and $423,000 in 1995.
Canadian Forest also provides a savings plan which is available to all of its
employees. Employees may contribute up to 4% of their salary, subject to
certain limitations, with Canadian Forest matching the employee contribution
in full. Certain limitations are in effect with respect to withdrawals from
the plan. Canadian Forest's contribution to the plan was $117,000 in 1997
and $95,000 in 1996.
EXECUTIVE RETIREMENT AGREEMENTS:
The Company entered into agreements in December 1990 (the Agreements) with
certain former executives and directors (the Retirees) whereby each executive
retired from the employ of the Company as of December 28, 1990. Pursuant to
the terms of the Agreements, the Retirees are entitled to receive
supplemental retirement payments from the Company in addition to the amounts
to which they are entitled under the Company's retirement plan. In addition,
the Retirees and their spouses are entitled to lifetime coverage under the
Company's group medical and dental plans, tax and other financial services,
and payments by the Company in connection with certain club membership dues.
The Retirees also continued to participate in the Company's royalty bonus
program until December 31, 1995. The Company has also agreed to maintain
certain life insurance policies in effect at December 1990, for the benefit
of each of the Retirees.
The Company's obligation to one retiree under a revised retirement agreement
was payable in Common Stock or cash, at the Company's option, in May of each
year from 1993 through 1996 at approximately $190,000 per year with the
balance of $149,000 paid in May 1997. The Agreements for the other six
Retirees provide for supplemental retirement payments totaling approximately
$970,000 in 1998 and approximately $770,000 per year in 1999 and 2000.
The $2,090,000 present value of the amounts due under the agreements,
discounted at 13%, is included in other current and long-term liabilities.
LIFE INSURANCE:
The Company provides life insurance benefits for certain key employees and
retirees under split dollar life insurance plans. The premiums for the life
insurance policies were $921,000 in each of the years 1997, 1996 and 1995, of
which $831,000 is for policies for retired executives. Under the life
insurance plans, the Company is assigned a portion of the benefits which is
designed to recover the premiums paid.
68
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(10) EMPLOYEE BENEFITS (CONTINUED):
- -------------------------------------------------------------------------------
POSTRETIREMENT BENEFITS:
The Company accrues expected costs of providing postretirement benefits to
employees, their beneficiaries and covered dependents in accordance with
Statement of Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions," (Statement No. 106).
The following table sets forth the status of the postretirement benefit plan and
the amounts recognized in the Company's consolidated financial statements at
December 31:
1997 1996
---- ----
(In Thousands)
Retired participants $4,963 4,522
Active participants fully eligible for benefits 286 256
Other active participants 1,312 1,101
------ -----
Accumulated postretirement benefit obligation (APBO) 6,561 5,879
Plan assets at fair market value - -
------ -----
APBO in excess of plan assets 6,561 5,879
Unrecognized loss (764) (166)
------ -----
Accrued postretirement benefit liability $5,797 5,713
------ -----
------ -----
The discount rates used in determining the actuarial present value of the
APBO at December 31, 1997, 1996 and 1995 were 7.25%, 7.75% and 7.25%,
respectively.
The components of postretirement benefit expense for the years ended December
31, 1997, 1996 and 1995 are as follows:
1997 1996 1995
---- ---- ----
(In Thousands)
Service cost $147 131 83
Interest cost on APBO 454 418 421
---- ---- ----
Postretirement benefit cost $601 549 504
---- ---- ----
---- ---- ----
For 1997, a 1% increase in health care cost trends would have increased the
APBO by $922,000 and the service and interest cost by $85,000.
69
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(11) COMMITMENTS AND CONTINGENCIES:
- -------------------------------------------------------------------------------
Future rental payments for office facilities and equipment under the
remaining terms of noncancelable leases are $1,526,000, $1,425,000,
$1,225,000, $1,145,000 and $1,151,000 for the years ending December 31, 1998
through 2002, respectively.
Net rental payments applicable to exploration and development activities and
capitalized in the oil and gas property accounts aggregated $1,120,000 in
1997, $1,050,000 in 1996 and $972,000 in 1995. Net rental payments charged
to expense amounted to $4,149,000 in 1997, $3,336,000 in 1996 and $3,529,000
in 1995. Rental payments include the short-term lease of vehicles. There are
no leases which are accounted for as capital leases.
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.
As part of ProMark's gas marketing activities, ProMark has entered into fixed
price contracts to purchase and to resell natural gas through 1999. ProMark
has commitments to purchase and commitments to resell approximately 125,000
MCF per day through October 31, 1998 and approximately 7,000 MCF per day
thereafter through October 31, 1999. The Company could be exposed to loss in
the event that a counterparty to these agreements failed to perform in
accordance with the terms of the agreements.
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.
(12) FINANCIAL INSTRUMENTS:
- -------------------------------------------------------------------------------
ENERGY SWAPS AND COLLARS:
In order to hedge against the effects of declines in oil and natural gas
prices on the Company's future oil and gas production, the Company enters
into energy swap agreements with third parties and accounts for the
agreements as hedges based on analogy to the criteria set forth in Statement
of Financial Accounting Standards No. 80, "Accounting for Futures Contracts."
In a typical swap agreement, the Company receives the difference between a
fixed price per unit of production and a price based on an agreed-upon third
party index if the index price is lower. If the index price is higher, the
Company pays the difference. The Company's current swaps are settled on a
monthly basis. For the years ended December 31, 1997, 1996 and 1995, the
Company's gains (losses) under its swap agreements were $(7,439,000),
$(10,422,000) and $3,536,000, respectively. The Company also enters into
collar agreements with third parties that are accounted for as hedges. A
collar agreement is similar to a swap agreement, except that the Company
receives the difference between the floor price and the index price only if
the index price is below the floor price, and the Company pays the difference
between the ceiling price and the index price only if the index price is
above the ceiling price.
70
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(12) FINANCIAL INSTRUMENTS (CONTINUED):
- -------------------------------------------------------------------------------
The following table summarizes outstanding energy swaps at December 31, 1997:
1998 1999 2000 2001 2002
---- ---- ---- ---- ----
UNITED STATES(1)
Natural Gas Swaps:
Contract volumes (BBTU) 10,435 1,056 793 660 37
Weighted average price (per MMBTU) $ 2.33 2.21 2.15 2.19 2.80
Oil Swaps:
Contract volumes (MBBLS) 180 - - - -
Weighted average price (per barrel) $20.50 - - - -
CANADA(2)
Natural Gas Swaps:
Contract volumes (BBTU) 1,647 - - - -
Weighted average price (per MMBTU) $1.21 - - - -
Oil Swaps:
Contract volumes (MBBLS) 303 - - - -
Weighted average price (per barrel) $20.57 - - - -
(1) Settled on the basis of New York Mercantile Exchange prices.
(2) Settled on the basis of Alberta Energy Company "C" U.S. dollar prices.
71
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
Subsequent to December 31, 1997 the Company entered into eight additional
natural gas swaps. The swaps are for 36,000 MMBTU of natural gas per day
from March 1998 to November 1998 at fixed prices ranging from $1.62 per
MMBTU (AECO "C", U.S. $ basis) to $2.35 per MMBTU (NYMEX basis), with a
weighted average price of $2.29 per MMBTU.
The Company also uses basis swaps in connection with energy swaps to fix the
differential between the NYMEX price and the index price at which the hedged
gas is to be sold. At December 31, 1997 there were three basis swaps in
place, for a weighted average volume of approximately 11,000 MMBTU/day
through December 1998. Subsequent to December 31, 1997, the Company entered
into two additional basis swaps through September 1998, for a weighted
average volume of approximately 14,000 MMBTU/day.
The Company is exposed to off-balance-sheet risks associated with swap
agreements arising from movements in the prices of oil and natural gas and
from the unlikely event of non-performance by the counterparties to the swap
agreements.
72
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(12) FINANCIAL INSTRUMENTS (CONTINUED):
- -------------------------------------------------------------------------------
When the Company purchased Canadian Forest in January 1996, interest rate
swaps were in place to hedge the interest rate on Canadian Forest's bank debt.
These swaps which expire in 1998, fix the interest rate on approximately
$30,000,000 CDN of long-term debt. Prior to September 1997, amounts received
or paid upon monthly settlement were recorded as adjustments to the interest
expense related to the debt. Following the September 1997 repayment of
Canadian Forest's bank debt, however, the swaps are required to be marked to
market and any gains or losses resulting from changes in the market value
recorded in earnings.
Set forth below is the estimated fair value of certain on- and off-balance
sheet financial instruments, along with the methods and assumptions used to
estimate such fair values as of December 31, 1997:
CASH AND CASH EQUIVALENTS, ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE:
The carrying amount of these instruments approximates fair value due to their
short maturity.
PRODUCTION PAYMENT OBLIGATION:
The fair value of the Company's production payment obligation has been
estimated as approximately $9,400,000 by discounting the projected future
cash payments required under the agreement by 8.567%.
SENIOR SUBORDINATED NOTES:
The fair value of the Company's 8 3/4% Senior Subordinated Notes was
approximately $126,250,000, based upon quoted market prices of the Notes.
The fair value of the Company's 11 1/4% Senior Subordinated Notes was
approximately $9,327,000, based upon quoted market prices of the Notes.
INTEREST RATE SWAP AGREEMENTS:
The fair value of the Company's interest rate swap agreements was a loss of
approximately $635,000, which amount has been recorded as a liability at
December 31, 1997.
ENERGY SWAP AGREEMENTS:
The fair value of the Company's energy swap agreements was a gain of
approximately $2,324,000, based upon the estimated net amount the Company
would receive to terminate the agreements.
BASIS SWAP AGREEMENTS:
The fair value of the Company's basis swap agreements was a gain of
approximately $48,000, based upon the estimated net amount the Company would
receive to terminate the agreements.
(13) MAJOR CUSTOMERS:
- -------------------------------------------------------------------------------
The Company's sales to individual customers which exceeded 10% of the
Company's total revenue in 1995 (exclusive of the effects of energy swaps and
hedges) are shown below. No single customer accounted for more than 10% of
total revenue in 1997 or in 1996.
1995
--------------
(In Thousands)
Enron Affiliates $30,916
Chevron USA Production Company 11,893
The amount shown for Enron Affiliates includes oil and natural gas sales to
Enron Gas Marketing Inc., Enron Oil & Gas Company, EOTT Energy Corporation,
Cactus Funding Corporation, Cactus Hydrocarbon III Limited Partnership, Enron
Gas Services Corporation and Enron Reserve Acquisition. Approximately
$17,217,000 represents sales recorded for deliveries under volumetric
production payments.
73
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(14) GAS CONTRACT SETTLEMENT:
- -------------------------------------------------------------------------------
The Company had gas sales contracts with Columbia Gas Transmission (Columbia)
which were rejected by Columbia in 1991 in connection with its bankruptcy
proceedings. The Company had a secured claim of approximately $1,600,000
relating to Columbia's failure to pay the contract price for a period of time
prior to the rejection of the contracts. The Company also had an unsecured
claim relating to the rejection of the gas purchase contracts. In 1995, the
creditors reached agreement with Columbia regarding settlement of the various
claims. The Company received the amount recorded as a receivable from
Columbia and also recorded approximately $4,263,000 of revenue representing
the Company's portion of the settlement amount related to its unsecured
claim, net of a provision for royalties payable.
(15) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED):
- -------------------------------------------------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
1997
- ----
REVENUE $93,063 77,655 81,977 86,946
------- ------- ------- -------
------- ------- ------- -------
EARNINGS FROM OPERATIONS $10,607 2,231 6,738 11,079
------- ------- ------- -------
------- ------- ------- -------
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM $ 4,522 (3,196) 583 1,180
------- ------- ------- -------
------- ------- ------- -------
NET EARNINGS (LOSS) $ 4,522 (3,196) (11,776) 1,180
------- ------- ------- -------
------- ------- ------- -------
NET EARNINGS (LOSS) ATTRIBUTABLE TO COMMON STOCK $ 4,333 (3,196) (11,776) 1,180
------- ------- ------- -------
------- ------- ------- -------
BASIC EARNINGS (LOSS) PER SHARE BEFORE EXTRAORDINARY ITEM $ 0.14 (0.10) 0.02 0.03
BASIC EARNINGS (LOSS) PER SHARE $ 0.14 (0.10) (0.35) 0.03
DILUTED EARNINGS (LOSS) PER SHARE BEFORE EXTRAORDINARY ITEM $ 0.13 (0.10) 0.02 0.03
DILUTED EARNINGS (LOSS) PER SHARE $ 0.13 (0.10) (0.34) 0.03
1996
- ----
Revenue $60,406 79,705 83,565 92,411
------- ------- ------- -------
------- ------- ------- -------
Earnings from operations $ 7,072 4,692 6,185 10,542
------- ------- ------- -------
------- ------- ------- -------
Earnings (loss) before extraordinary item $ (386) (2,901) 879 3,547
------- ------- ------- -------
------- ------- ------- -------
Net earnings (loss) $ (386) (2,901) 879 5,713
------- ------- ------- -------
------- ------- ------- -------
Net earnings (loss) attributable to common stock $ (926) (3,441) 340 5,174
------- ------- ------- -------
------- ------- ------- -------
Basic earnings (loss) per share before extraordinary item $ (0.04) (0.14) 0.01 0.10
Basic earnings (loss) per share $ (0.04) (0.14) 0.01 0.18
Diluted earnings (loss) per share before extraordinary item $ (0.04) (0.14) 0.01 0.09
Diluted earnings (loss) per share $ (0.04) (0.14) 0.01 0.16
74
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(16) BUSINESS AND GEOGRAPHICAL SEGMENTS:
- -------------------------------------------------------------------------------
The Company operates in geographic segments in the United States and Canada,
and in two business segments as follows:
UNITED
STATES CANADA TOTAL
------ ------ ----
(IN THOUSANDS)
1997
- ----
GAS MARKETING AND PROCESSING:
REVENUE $ 863 183,536 184,399
-------- ------- -------
-------- ------- -------
DEPRECIATION AND DEPLETION EXPENSE $ - 2,343 2,343
-------- ------- -------
-------- ------- -------
OPERATING PROFIT $ 863 5,346 6,209
-------- ------- -------
-------- ------- -------
IDENTIFIABLE ASSETS $ - 48,792 48,792
-------- ------- -------
-------- ------- -------
CAPITAL EXPENDITURES $ - 30 30
-------- ------- -------
-------- ------- -------
OIL AND GAS OPERATIONS:
REVENUE $100,895 54,347 155,242
-------- ------- -------
-------- ------- -------
DEPRECIATION AND DEPLETION EXPENSE $ 52,320 25,328 77,648
-------- ------- -------
-------- ------- -------
OPERATING PROFIT $ 27,712 13,598 41,310
-------- ------- -------
-------- ------- -------
IDENTIFIABLE ASSETS $378,373 220,617 598,990
-------- ------- -------
-------- ------- -------
CAPITAL EXPENDITURES $ 98,550 57,615 156,165
-------- ------- -------
-------- ------- -------
75
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(16) BUSINESS AND GEOGRAPHICAL SEGMENTS (CONTINUED):
- -------------------------------------------------------------------------------
UNITED
STATES CANADA TOTAL
------ ------ ----
(IN THOUSANDS)
1996
- ----
Gas marketing and processing:
Revenue $ 927 186,447 187,374
-------- ------- -------
-------- ------- -------
Depreciation and depletion expense $ - 2,263 2,263
-------- ------- -------
-------- ------- -------
Operating profit $ 927 5,478 6,405
-------- ------- -------
-------- ------- -------
Identifiable assets $ - 54,215 54,215
-------- ------- -------
-------- ------- -------
Capital expenditures $ - 6,183 6,183
-------- ------- -------
-------- ------- -------
Oil and gas operations:
Revenue $ 80,811 47,902 128,713
-------- ------- -------
-------- ------- -------
Depreciation and depletion expense $ 39,880 20,925 60,805
-------- ------- -------
-------- ------- -------
Operating profit $ 21,142 14,567 35,709
-------- ------- -------
-------- ------- -------
Identifiable assets $326,399 182,844 509,243
-------- ------- -------
-------- ------- -------
Capital expenditures $ 74,734 169,384 244,118
-------- ------- -------
-------- ------- -------
In 1995 the Company's only business segment was oil and gas operations, which
were conducted entirely in the United States.
76
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED):
- -------------------------------------------------------------------------------
The following information is presented in accordance with Statement of
Financial Accounting Standards No. 69, "Disclosure about Oil and Gas
Producing Activities," (Statement No. 69), except as noted.
(A) COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES -
The following costs were incurred in oil and gas exploration and development
activities during the years ended December 31, 1997, 1996 and 1995:
UNITED
STATES CANADA TOTAL
------ ------ ----
(IN THOUSANDS)
1997
- ----
PROPERTY ACQUISITION COSTS (UNDEVELOPED
LEASES AND PROVED PROPERTIES) $ 1,704 6,675 8,379
EXPLORATION COSTS 50,686 14,752 65,438
DEVELOPMENT COSTS 46,160 36,218 82,378
-------- ------- -------
TOTAL $98,550 57,645 156,195
-------- ------- -------
-------- ------- -------
1996
- ----
Property acquisition costs (undeveloped
leases and proved properties) $16,122 142,833 (1) 158,955
Exploration costs 36,696 6,743 43,439
Development costs 21,916 19,808 41,724
-------- ------- -------
Total $74,734 169,384 244,118
-------- ------- -------
-------- ------- -------
1995
- ----
Property acquisition costs (undeveloped
leases and proved properties) $ 844 25,963 (2) 26,807
Exploration costs 12,739 - 12,739
Development costs 13,198 - 13,198
-------- ------- -------
Total $26,781 25,963 52,744
-------- ------- -------
-------- ------- -------
(1) Consists primarily of the oil and gas properties acquired in the purchase
of Canadian Forest.
(2) Consists of the oil and gas properties acquired in the purchase of Saxon.
(B) AGGREGATE CAPITALIZED COSTS - The aggregate capitalized costs relating
to oil and gas activities as of December 31 for the years indicated are as
follows:
1997 1996 1995
------ ------ ------
(IN THOUSANDS)
Costs related to proved properties $ 1,521,325 1,381,289 1,169,636
Costs related to unproved properties:
Costs subject to depletion 12,217 32,007 18,011
Costs not subject to depletion 60,901 43,916 28,380
----------- ---------- ----------
1,594,443 1,457,212 1,216,027
Less accumulated depletion and valuation allowance (1,075,940) (1,001,604) (941,482)
----------- ---------- ----------
----------- ---------- ----------
$ 518,503 455,608 274,545
----------- ---------- ----------
----------- ---------- ----------
77
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- -------------------------------------------------------------------------------
(C) RESULTS OF OPERATIONS FROM PRODUCING ACTIVITIES - Results of operations
from producing activities for the years ended December 31, 1997, 1996 and
1995 are presented below. Income taxes are different from income taxes shown
in the Consolidated Statements of Operations because this table excludes
general and administrative and interest expense.
UNITED
STATES CANADA TOTAL
------ ------ -----
(IN THOUSANDS)
1997
- ----
OIL AND GAS SALES $100,895 54,347 155,242
PRODUCTION EXPENSE 20,863 15,421 36,284
DEPLETION EXPENSE 51,741 24,708 76,449
INCOME TAX EXPENSE - 7,191 7,191
-------- ------- -------
72,604 47,320 119,924
-------- ------- -------
RESULTS OF OPERATIONS FROM PRODUCING ACTIVITIES $28,291 7,027 35,318
-------- ------- -------
-------- ------- -------
1996
- ----
Oil and gas sales $80,811 47,902 128,713
Production expense 19,789 12,410 32,199
Depletion expense 39,331 20,297 59,628
Income tax expense - 6,864 6,864
-------- ------- -------
59,120 39,571 98,691
-------- ------- -------
Results of operations from producing activities $21,691 8,331 30,022
-------- ------- -------
-------- ------- -------
1995
- ----
Oil and gas sales $82,275 - 82,275
Production expense 22,463 - 22,463
Depletion expense 42,973 - 42,973
-------- ------- -------
65,436 - 65,436
-------- ------- -------
Results of operations from producing activities $16,839 - 16,839
-------- ------- -------
-------- ------- -------
(D) ESTIMATED PROVED OIL AND GAS RESERVES - The Company's estimate of its
proved and proved developed future net recoverable oil and gas reserves and
changes for 1995, 1996 and 1997 follows. The Canadian reserves at December
31, 1997 and 1996 and 1995 include 100% of the reserves owned by Saxon, a
consolidated subsidiary in which the Company holds a majority interest.
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions; i.e.,
prices and costs as of the date the estimate is made. Prices include
consideration of changes in existing prices provided only by contractual
arrangement, including energy swap agreements (see Note 12), but not on
escalations based on future conditions. Purchases of reserves in place
represent volumes recorded on the closing dates of the acquisitions for
financial accounting purposes.
78
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- -------------------------------------------------------------------------------
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the
application of fluid injection or other improved mechanisms of primary
recovery are included as "proved developed reserves" only after testing by a
pilot project or after the operation of an installed program has confirmed
through production response that increased recovery will be achieved.
The Company's presentation of estimated proved oil and gas reserves excludes,
for 1995 and 1996, those quantities attributable to future deliveries
required under volumetric production payments (see Note 6). In order to
calculate such amounts, the Company assumed that deliveries under volumetric
production payments were made as scheduled at expected BTU factors, and that
delivery commitments were satisfied through delivery of actual volumes as
opposed to cash settlements.
On June 30, 1997 the Company purchased from Enron the obligation related to
its last remaining volumetric production payment. Net reserves of
approximately 3.1 BCFE, which were dedicated to repayment of this volumetric
production payment, reverted to the Company's interest.
The Company has also presented for 1996 and 1995, as additional information,
proved oil and gas reserves including quantities attributable to future
deliveries required under volumetric production payments. The Company
believes that this information is informative to readers of its financial
statements as the related oil and gas property costs and deferred revenue are
included on the Company's balance sheets for 1996 and 1995. This additional
information is not presented in accordance with Statement No. 69; however, the
Company believes this additional information is useful in assessing its
reserve acquisitions and financial position on a comprehensive basis.
79
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- -------------------------------------------------------------------------------
LIQUIDS GAS
--------------------------- -----------------------------
(MBBLS) (MMCF)
UNITED UNITED
STATES CANADA TOTAL STATES CANADA TOTAL
------ ------ ----- ------ ------ -----
Balance at December 31, 1994 7,313 - 7,313 231,638 - 231,638
Revisions of previous estimates (227) - (227) 2,398 - 2,398
Extensions and discoveries 18 - 18 6,861 - 6,861
Production (1,028) - (1,028) (24,222) - (24,222)
Sales of reserves in place (6) - (6) (2,438) - (2,438)
Purchases of reserves in place 59 4,338 4,397 1,435 16,218 17,653
------ ------ ------ ------- ------- -------
Balance at December 31, 1995 6,129 4,338 10,467 215,672 16,218 231,890
Volumes attributable to volumetric
production payments 74 - 74 6,238 - 6,238
------ ------ ------ ------- ------- -------
Balance at December 31, 1995, including
volumes attributable to volumetric
production payments 6,203 4,338 10,541 221,910 16,218 238,128
------ ------ ------ ------- ------- -------
------ ------ ------ ------- ------- -------
Balance at December 31, 1995 6,129 4,338 10,467 215,672 16,218 231,890
Revisions of previous estimates 335 (431) (96) (4,989) (3,446) (8,435)
Extensions and discoveries 357 4,440 4,797 32,507 7,779 40,286
Production (1,030) (1,645) (2,675) (25,456) (13,872) (39,328)
Sales of reserves in place (16) (612) (628) (1,132) (326) (1,458)
Purchases of reserves in place 23 12,126 12,149 14,653 96,572 111,225
------ ------ ------ ------- ------- -------
Balance at December 31, 1996 5,798 18,216 24,014 231,255 102,925 334,180
Volumes attributable to volumetric
production payments - - - 3,070 - 3,070
------ ------ ------ ------- ------- -------
Balance at December 31, 1996, including
volumes attributable to volumetric
production payments 5,798 18,216 24,014 234,325 102,925 337,250
------ ------ ------ ------- ------- -------
------ ------ ------ ------- ------- -------
BALANCE AT DECEMBER 31, 1996 5,798 18,216 24,014 231,255 102,925 334,180
REVISIONS OF PREVIOUS ESTIMATES 965 247 1,212 23,173 12,779 35,952
EXTENSIONS AND DISCOVERIES 876 1,688 2,564 37,759 12,005 49,764
PRODUCTION (1,267) (1,940) (3,207) (34,018) (15,017) (49,035)
SALES OF RESERVES IN PLACE (268) 11 (257) (4,349) 217 (4,132)
PURCHASES OF RESERVES IN PLACE 22 288 310 1,033 7,483 8,516
SETTLEMENT OF VOLUMETRIC PRODUCTION PAYMENT - - - 3,070 - 3,070
------ ------ ------ ------- ------- -------
BALANCE AT DECEMBER 31, 1997 6,126 18,510 24,636 257,923 120,392 378,315
------ ------ ------ ------- ------- -------
------ ------ ------ ------- ------- -------
PRO FORMA RESERVES GIVING EFFECT TO THE
LOUISIANA ACQUISITION (SEE NOTE 2) 18,709 18,510 37,219 366,382 120,392 486,774
------ ------ ------ ------- ------- -------
------ ------ ------ ------- ------- -------
80
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- -------------------------------------------------------------------------------
OIL AND CONDENSATE GAS
--------------------------- --------------------------
(MBBLS) (MMCF)
UNITED UNITED
STATES CANADA TOTAL STATES CANADA TOTAL
------ ------ ----- ------ ------ -----
Proved developed reserves at:
December 31, 1994 6,775 - 6,775 179,574 - 179,574
December 31, 1995 5,678 3,188 8,866 156,471 14,184 170,655
December 31, 1996 5,311 13,260 18,571 165,629 70,856 236,485
DECEMBER 31, 1997 5,493 14,291 19,784 179,986 109,849 289,835
Pro forma proved developed reserves
giving effect to the Louisiana Acquisition
(see Note 2) 14,527 14,291 28,818 262,724 109,849 372,573
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS - Future oil
and gas sales and production and development costs have been estimated using
prices and costs in effect at the end of the years indicated, except in those
instances where the sale of oil and natural gas is covered by contracts,
energy swap agreements or volumetric production payments. At December 31,
1997, 1996 and 1995, the Canadian amounts include 100% of amounts
attributable to the reserves owned by Saxon, a consolidated subsidiary in
which the Company holds a majority interest. In the case of contracts, the
applicable contract prices, including fixed and determinable escalations,
were used for the duration of the contract. Thereafter, the current spot
price was used. Future oil and gas sales also include the estimated effects
of existing energy swap agreements as discussed in Note 12.
Future income tax expenses are estimated using the statutory tax rate of 35%
in the United States and a combined Federal and Provincial rate of 44.62% in
Canada. Estimates for future general and administrative and interest expense
have not been considered.
81
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- -------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
Changes in the demand for oil and natural gas, inflation and other factors
make such estimates inherently imprecise and subject to substantial revision.
This table should not be construed to be an estimate of the current market
value of the Company's proved reserves. Management does not rely upon the
information that follows in making investment decisions.
The Company's presentation of the standardized measure of discounted future
net cash flows and changes therein excludes, for 1996 and 1995, amounts
attributable to future deliveries required under volumetric production
payments. In order to calculate such amounts, the Company has assumed that
deliveries under volumetric production payments were made as scheduled, that
production costs corresponding to the volumes delivered were incurred by the
Company at average rates for the properties subject to the production
payments, and that delivery commitments were satisfied through delivery of
actual volumes as opposed to cash settlements.
On June 30, 1997 the Company purchased from Enron the obligation related to
its last remaining volumetric production payment. Net reserves of
approximately 3.1 BCFE, which were dedicated to repayment of this volumetric
production payment, reverted to the Company's interest.
The Company has also presented for 1996 and 1995, as additional information,
the standardized measure of discounted future net cash flows and changes
therein including amounts attributable to future deliveries required under
volumetric production payments. The Company believes that this information
is informative to readers of its financial statements because the related oil
and gas property costs and deferred revenue were shown on the Company's
balance sheets for 1996 and 1995. This additional information is not
required to be presented in accordance with Statement No. 69; however, the
Company believes this additional information is useful in assessing its
reserve acquisitions and financial position on a comprehensive basis.
DECEMBER 31, 1997
-------------------------------
UNITED
STATES CANADA TOTAL
------ ------ -----
(IN THOUSANDS)
FUTURE OIL AND GAS SALES $ 759,556 470,121 1,229,677
FUTURE PRODUCTION AND DEVELOPMENT COSTS (273,850) (193,733) (467,583)
--------- -------- ---------
FUTURE NET REVENUE 485,706 276,388 762,094
10% ANNUAL DISCOUNT FOR ESTIMATED TIMING OF CASH FLOWS (176,507) (99,081) (275,588)
--------- -------- ---------
PRESENT VALUE OF FUTURE NET CASH FLOWS BEFORE INCOME TAXES 309,199 177,307 486,506
PRESENT VALUE OF FUTURE INCOME TAX EXPENSE (19,899) (27,037) (46,936)
--------- -------- ---------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS $ 289,300 150,270 439,570
--------- -------- ---------
--------- -------- ---------
PRO FORMA PRESENT VALUE OF FUTURE NET CASH FLOWS BEFORE
INCOME TAXES GIVING EFFECT TO THE LOUISIANA
ACQUISITION (SEE NOTE 2) $ 579,780 177,307 757,087
--------- -------- ---------
--------- -------- ---------
PRO FORMA STANDARDIZED MEASURE OF DISCOUNTED CASH FLOWS
GIVING EFFECT TO THE LOUISIANA ACQUISITION (SEE NOTE 2) $ 554,867 150,270 705,137
--------- -------- ---------
--------- -------- ---------
Undiscounted future income tax expense was $45,911,000 in the United States and
$57,981,000 in Canada at December 31, 1997.
82
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- -------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
DECEMBER 31, 1996
-------------------------------
UNITED
STATES CANADA TOTAL
------ ------ -----
(IN THOUSANDS)
Future oil and gas sales $ 964,943 580,563 1,545,506
Future production and development costs (258,866) (168,136) (427,002)
--------- -------- ---------
Future net revenue 706,077 412,427 1,118,504
10% annual discount for estimated timing of cash flows (250,527) (165,788) (416,315)
--------- -------- ---------
Present value of future net cash flows before income taxes 455,550 246,639 702,189
Present value of future income tax expense (71,339) (70,981) (142,320)
--------- -------- ---------
Standardized measure of discounted future net cash flows 384,211 175,658 559,869
Additional disclosures:
Amounts attributable to volumetric production payments 3,126 - 3,126
--------- -------- ---------
Total discounted future net cash flows, including amounts
attributable to volumetric production payments $387,337 175,658 562,995
--------- -------- ---------
--------- -------- ---------
Undiscounted future income tax expense was $134,835,000 in the United
States and $127,833,000 in Canada at December 31, 1996.
DECEMBER 31, 1995
-------------------------------
UNITED
STATES CANADA TOTAL
------ ------ -----
(IN THOUSANDS)
Future oil and gas sales $ 554,609 93,021 647,630
Future production and development costs (195,399) (43,060) (238,459)
--------- ------- ---------
Future net revenue 359,210 49,961 409,171
10% annual discount for estimated timing of cash flows (122,528) (19,108) (141,636)
--------- ------- ---------
Present value of future net cash flows before income taxes 236,682 30,853 267,535
Present value of future income tax expense (8,855) (1,763) (10,618)
--------- ------- ---------
Standardized measure of discounted future net cash flows 227,827 29,090 256,917
Additional disclosures:
Amounts attributable to volumetric production payments 8,476 - 8,476
--------- ------- ---------
Total discounted future net cash flows, including amounts
attributable to volumetric production payments $ 236,303 29,090 265,393
--------- ------- ---------
--------- ------- ---------
Undiscounted future income tax expense was $22,316,000 in the United States and
$2,924,000 in Canada at December 31, 1995.
83
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- -------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES - An analysis of the changes in the
standardized measure of discounted future net cash flows during each of the
last three years follows. At December 31, 1997, 1996 and 1995, the Canadian
amounts include 100% of the reserves owned by Saxon, a consolidated subsidiary
in which the Company holds a majority interest.
DECEMBER 31, 1997
-------------------------------
UNITED
STATES CANADA TOTAL
------ ------ -----
(IN THOUSANDS)
Standardized measure of discounted future net cash flows relating
to proved oil and gas reserves, at beginning of year $ 384,211 175,658 559,869
Changes resulting from:
Sales of oil and gas, net of production costs (80,895) (38,926) (119,821)
Net changes in prices and future production costs (218,986) (110,526) (329,512)
Net changes in future development costs (22,830) (19,905) (42,735)
Extensions, discoveries and improved recovery 48,090 19,022 67,112
Previously estimated development costs incurred during the period 42,507 35,329 77,836
Revisions of previous quantity estimates 38,055 13,445 51,500
Sales of reserves in place (5,066) 301 (4,765)
Purchases of reserves in place 3,142 7,264 10,406
Settlement of volumetric production payment 3,126 - 3,126
Accretion of discount on reserves at beginning of year before
income taxes 45,926 24,664 70,590
Net change in income taxes 52,020 43,944 95,964
--------- ------- --------
Standardized measure of discounted future net cash flows relating
to proved oil and gas reserves, at end of year $ 289,300 150,270 439,570
--------- ------- --------
--------- ------- --------
Pro forma standardized measure of discounted future
net cash flows giving effect to the Louisiana
Acquisition (see Note 2) $ 554,867 150,270 705,137
--------- ------- --------
--------- ------- --------
The computation of the standardized measure of discounted future net cash
flows relating to proved oil and gas reserves at December 31, 1997 was based
on average natural gas prices of approximately $2.55 per MCF in the U.S. and
approximately $1.30 per MCF in Canada and on average liquids prices of
approximately $16.73 per barrel in the U.S. and approximately $13.71 per
barrel in Canada. Subsequent to December 31, 1997 the prices of oil and gas
decreased significantly. During March 1998, the Company was receiving average
natural gas prices of approximately $2.27 per MCF in the U.S. and
approximately $1.23 per MCF in Canada. The West Texas Intermediate price for
crude oil decreased from $14.75 per barrel at December 31, 1997 to $12.25 per
barrel at March 1, 1998. Had the lower March prices been used, the Company's
standardized measure of discounted future net cash flows relating to proved
oil and gas reserves at December 31, 1997 would have been reduced.
84
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- -------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
DECEMBER 31, 1996
-------------------------------
UNITED
STATES CANADA TOTAL
------ ------ -----
(IN THOUSANDS)
Standardized measure of discounted future net cash flows relating
to proved oil and gas reserves, at beginning of year $227,827 29,090 256,917
Changes resulting from:
Sales of oil and gas, net of production costs (56,768) (35,492) (92,260)
Net changes in prices and future production costs 169,975 96,547 266,522
Net changes in future development costs (14,192) (8,256) (22,448)
Extensions, discoveries and improved recovery 60,423 37,491 97,914
Previously estimated development costs incurred during the period 19,734 18,939 38,673
Revisions of previous quantity estimates (4,396) (8,054) (12,450)
Sales of reserves in place (2,405) (3,993) (6,398)
Purchases of reserves in place 21,948 115,518 137,466
Accretion of discount on reserves at beginning of year before
income taxes 24,549 3,085 27,634
Net change in income taxes (62,484) (69,217) (131,701)
-------- ------- --------
Standardized measure of discounted future net cash flows relating
to proved oil and gas reserves, at end of year 384,211 175,658 559,869
Additional disclosures:
Amounts attributable to volumetric production payments 3,126 - 3,126
--------- ------- --------
Total discounted future net cash flows relating to proved
oil and gas reserves, including amounts attributable to
volumetric production payments, at end of year $ 387,337 175,658 562,995
--------- ------- --------
--------- ------- --------
The computation of the standardized measure of discounted future net cash
flows relating to proved oil and gas reserves at December 31, 1996 was based
on average natural gas prices of approximately $3.50 per MCF in the U.S. and
approximately $2.10 per MCF in Canada and on average liquids prices of
approximately $26.25 per barrel in the U.S. and approximately $19.10 per
barrel in Canada.
85
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- -------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
DECEMBER 31, 1995
-------------------------------
UNITED
STATES CANADA TOTAL
------ ------ -----
(IN THOUSANDS)
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves, at beginning of
year $207,549 - 207,549
Changes resulting from:
Sales of oil and gas, net of production costs (48,090) - (48,090)
Net changes in prices and future production costs 43,991 - 43,991
Net changes in future development costs (3,392) - (3,392)
Extensions, discoveries and improved recovery 7,231 - 7,231
Previously estimated development costs incurred
during the period 7,633 - 7,633
Revisions of previous quantity estimates 127 - 127
Sales of reserves in place (3,114) - (3,114)
Purchases of reserves in place 865 30,853 31,718
Accretion of discount on reserves at beginning of year before
income taxes 23,102 - 23,102
Net change in income taxes (8,075) (1,763) (9,838)
-------- ------ -------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves, at end of year 227,827 29,090 256,917
Additional disclosures:
Amounts attributable to volumetric production payments 8,476 - 8,476
Total discounted future net cash flows relating to proved
oil and gas reserves, including amounts attributable to
volumetric production payments, at end of year $236,303 29,090 265,393
-------- ------ -------
-------- ------ -------
The computation of the standardized measure of discounted future net cash
flows relating to proved oil and gas reserves at December 31, 1995 was based
on average natural gas prices of approximately $2.00 per MCF in the U.S. and
approximately $.99 per MCF in Canada and on average liquids prices of
approximately $19.96 per barrel in the U.S. and approximately $16.87 per
barrel in Canada.
86
PART III
For information concerning Item 10 - Directors and Executive Officers of the
Registrant, Item 11 - Executive Compensation, Item 12 - Security Ownership of
Certain Beneficial Owners and Management and Item 13 - Certain Relationships
and Related Transactions, see the definitive Proxy Statement of Forest Oil
Corporation relative to the Annual Meeting of Shareholders to be held in May,
1998 which will be filed with the Securities and Exchange Commission, which
information is incorporated herein by reference. For information concerning
Item 10 - Executive Officers of Registrant, see Part I - Item 4A.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) (1) Financial Statements
1. Independent Auditors' Report
2. Consolidated Balance Sheets - December 31, 1997 and 1996
3. Consolidated Statements of Operations - Years ended December
31, 1997, 1996 and 1995
4. Consolidated Statements of Shareholders' Equity - Years
ended December 31, 1997, 1996 and 1995
5. Consolidated Statements of Cash Flows - Years ended December
31, 1997, 1996 and 1995
6. Notes to Consolidated Financial Statements - Years ended
December 31, 1997, 1996 and 1995
(2) Financial Statement Schedules
All schedules have been omitted because the information is either
not required or is set forth in the financial statements or the
notes thereto.
(3) Exhibits - Forest shall, upon written request to Daniel L.
McNamara, Corporate Secretary of Forest, addressed to Forest Oil
Corporation, 1600 Broadway, Suite 2200, Denver, CO 80202, provide
copies of each of the following Exhibits:
Exhibit 3(i) Restated Certificate of Incorporation of Forest Oil
Corporation dated October 14, 1993, incorporated herein by reference to
Exhibit 3(i) to Form 10-Q for Forest Oil Corporation for the quarter ended
September 30, 1993 (File No. 0-4597).
Exhibit 3(i)(a) Certificate of Amendment of the Restated Certificate of
Incorporation dated as of July 20, 1995, incorporated herein by reference to
Exhibit 3(i)(a) to Form 10-Q for Forest Oil Corporation for the quarter ended
June 30, 1995 (File No. 0-4597).
Exhibit 3(i)(b) Certificate of Amendment of Restated Certificate of
Incorporation dated as of July 26, 1995, incorporated herein by reference to
Exhibit 3(i)(b) to Form 10-Q for Forest Oil Corporation for the quarter ended
June 30, 1995 (File No. 0-4597).
87
Exhibit 3(i)(c) Certificate of Amendment of the Restated Certificate of
Incorporation dated as of January 5, 1996, incorporated herein by reference
to Exhibit 3(i)(c) to Forest Oil Corporation's Registration Statement on Form
S-2 (File No. 33-64949).
Exhibit 3(ii) Restated By-Laws of Forest Oil Corporation as of May 9,
1990, Amendment No. 1 to By-Laws dated as of April 2, 1991, Amendment No. 2
to By-Laws dated as of May 8, 1991, Amendment No. 3 to By-Laws dated as of
July 30, 1991, Amendment No. 4 to By-Laws dated as of January 17, 1992,
Amendment No. 5 to By-Laws dated as of March 18, 1993 and Amendment No. 6 to
By-Laws dated as of September 14, 1993, incorporated herein by reference to
Exhibit 3(ii) to Form 10-Q for Forest Oil Corporation for the quarter ended
September 30, 1993 (File No. 0-4597).
Exhibit 3(ii)(a) Amendment No. 7 to By-Laws dated as of December 3, 1993,
incorporated herein by reference to Exhibit 3(ii)(a) to Form 10-K for Forest
Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
Exhibit 3(ii)(b) Amendment No. 8 to By-Laws dated as of February 24, 1994,
incorporated herein by reference to Exhibit 3(ii)(b) to Form 10-K for Forest
Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
Exhibit 3(ii)(c) Amendment No. 9 to By-Laws dated as of May 15, 1995,
incorporated herein by reference to Exhibit 3(ii)(c) to Form 10-Q for Forest
Oil Corporation for the quarter ended June 30, 1995 (File No. 0-4597).
Exhibit 3(ii)(d) Amendment No. 10 to By-Laws dated as of July 27, 1995,
incorporated herein by reference to Exhibit 3(ii)(d) to Form 10-Q for Forest
Oil Corporation for the quarter ended June 30, 1995 (File No. 0-4597).
Exhibit 4.1 Indenture dated as of September 8, 1993 between Forest Oil
Corporation and Shawmut Bank, Connecticut, (National Association),
incorporated herein by reference to Exhibit 4.1 to Form 10-Q for Forest Oil
Corporation for the quarter ended September 30, 1993 (File No. 0-4597).
Exhibit 4.2 First Supplemental Indenture dated as of February 8, 1996
among Forest Oil Corporation, 611852 Saskatchewan Ltd. and Fleet National
Bank of Connecticut (formerly known as Shawmut Bank, Connecticut, National
Association, which was formerly known as The Connecticut Bank), incorporated
herein by reference to Exhibit 4.2 to Form 10-K for Forest Oil Corporation
for the year ended December 31, 1995 (File No. 0-4597).
*Exhibit 4.3 Second Supplemental Indenture dated as of September 12, 1997
between Forest Oil Corporation, 611852 Saskatchewan Ltd. and State Street
Bank and Trust Company (as successor in interest to Fleet National Bank of
Connecticut (formerly known as Shawmut Bank Connecticut, National
Association)).
Exhibit 4.4 Indenture dated as of September 29, 1997 among Canadian
Forest Oil Ltd., Forest Oil Corporation and State Street Bank and Trust
Company, incorporated herein by reference to Exhibit 4.1 to Forest Oil
Corporation's Registration Statement on Form S-4 dated October 31, 1997 (File
No. 333-39255).
*Exhibit 4.5 Registration Agreement dated February 2, 1998 by and among
Canadian Forest Oil Ltd., Forest Oil Corporation and Morgan Stanley & Co.
Incorporated.
Exhibit 4.6 Amended and Restated Credit Agreement dated as of August 31,
1995 between Forest Oil Corporation and Subsidiaries, Borrower and Subsidiary
Guarantors and The Chase Manhattan Bank (National Association), as agent,
incorporated herein by reference to Exhibit 4.1 to Form 10-Q for Forest Oil
Corporation for the quarter ended September 30, 1995 (File No. 0-4597).
88
*Exhibit 4.7 Third Amended and Restated Credit Agreement dated as of
February 3, 1998 between Forest Oil Corporation and Subsidiary Guarantors and
The Chase Manhattan Bank, as agent.
Exhibit 4.8 Deed of Trust, Mortgage, Security Agreement, Assignment of
Production, Financing Statement (Personal Property Including Hydrocarbons),
and Fixture Filing dated as of December 1, 1993, incorporated herein by
reference to Exhibit 4.6 to Form 10-K for Forest Oil Corporation for the year
ended December 31, 1993 (File No. 0-4597).
Exhibit 4.9 Amendment No. 1 dated as of June 3, 1994 to the Deed of
Trust, Mortgage, Security Agreement, Assignment of Production, Financing
Statement (Personal Property including Hydrocarbons) and Fixture Filing dated
as of December 1, 1993 between Forest Oil Corporation and The Chase Manhattan
Bank (National Association), as agent, incorporated herein by reference to
Exhibit 4.9 of Form 10-K for Forest Oil Corporation for the year ended
December 31, 1994 (File No. 0-4597).
Exhibit 4.10 Amendment No. 2 dated as of August 31, 1995 to the Deed of
Trust, Mortgage, Security Agreement, Assignment of Production, Financing
Statement (Personal Property including Hydrocarbons) and Fixture Filing dated
as of December 1, 1993 between Forest Oil Corporation and The Chase Manhattan
Bank (National Association), as agent, incorporated herein by reference to
Exhibit 4.14 to Form 10-K for Forest Oil Corporation for the year ended
December 31, 1995 (File No. 0-4597).
Exhibit 4.11 Amendment No. 2 dated as of January 31, 1997 to the Deed of
Trust, Mortgage, Security Agreement, Assignment of Production, Financing
Statement (Personal Property including Hydrocarbons) and Fixture Filing dated
as of June 3, 1994 between Forest Oil Corporation and The Chase Manhattan
Bank, as agent, incorporated herein by reference to Exhibit 4.8 to Form 10-K
for Forest Oil Corporation for the year ended December 31, 1996 (File No.
0-4597).
Exhibit 4.12 Amendment No. 3 dated as of January 31, 1997 to the Deed of
Trust, Mortgage, Security Agreement, Assignment of Production, Financing
Statement (Personal Property including Hydrocarbons) and Fixture Filing dated
as of December 1, 1993 between Forest Oil Corporation and The Chase Manhattan
Bank, as agent, incorporated herein by reference to Exhibit 4.9 to Form 10-K
for Forest Oil Corporation for the year ended December 31, 1996 (File No.
0-4597).
*Exhibit 4.13 Amendment No. 4 dated as of February 3, 1998 to Deed of
Trust, Mortgage, Security Agreement, Assignment of Production, Financing
Statement (Personal Property including Hydrocarbons and Fixture Filing dated
as of December 1, 1993 between Forest Oil Corporation and The Chase Manhattan
Bank, as agent.
*Exhibit 4.14 Amendment No. 5 dated as of February 3, 1998 to Deed of
Trust, Mortgage, Security Agreement, Assignment of Production, Financing
Statement (Personal Property including Hydrocarbons and Fixture Filing dated
as of December 1, 1993 between Forest Oil Corporation and The Chase Manhattan
Bank, as agent).
Exhibit 4.15 Deed of Trust, Mortgage, Security Agreement, Assignment of
Production, Financing Statement (Personal Property including Hydrocarbons)
and Fixture Filing dated as of June 3, 1994 between Forest Oil Corporation
and The Chase Manhattan Bank (National Association), as agent, incorporated
herein by reference to Exhibit 4.9 of Form 10-K for Forest Oil Corporation
for the year ended December 31, 1994 (File No. 0-4597).
Exhibit 4.16 Amendment No. 1 dated as of August 31, 1995 to Deed of
Trust, Mortgage, Security Agreement, Assignment of Production, Financing
Statement (Personal Property Including Hydrocarbons), and Fixture Filing
dated June 3, 1994, incorporated herein by reference to Exhibit 4.16 on Form
10-K for Forest Oil Corporation for the year ended December 31, 1995 (File
No. 0-4597).
Exhibit 4.17 Rights Agreement between Forest Oil Corporation and Mellon
Securities Trust Company, as Rights Agent dated as of October 14, 1993,
incorporated herein by reference to Exhibit 4.3 to Form 10-Q for Forest Oil
Corporation for the quarter ended September 30, 1993 (File No. 0-4597).
89
Exhibit 4.18 Amendment No. 1 dated as of July 27, 1995 to Rights
Agreement dated as of October 14, 1993 between Forest Oil Corporation and
Mellon Securities Trust Company, incorporated herein by reference to Exhibit
99.5 of Form 8-K for Forest Oil Corporation dated October 11, 1995 (File No.
0-4597).
*Exhibit 10.1 First Amendment to Shareholders Agreement dated as of
January 24, 1996 between Forest Oil Corporation and The Anschutz Corporation.
Exhibit 10.2 Description of Executive Life Insurance Plan, incorporated
herein by reference to Exhibit 10.2 to Form 10-K for Forest Oil Corporation
for the year ended December 31, 1991 (File No. 0-4597).
Exhibit 10.3 Form of non-qualified Executive Deferred Compensation
Agreement, incorporated herein by reference to Exhibit 10.3 to Form 10-Q for
Forest Oil Corporation for the years ended December 31, 1990 (File No.
0-4597).
Exhibit 10.4 Form of non-qualified Supplemental Executive Retirement
Plan, incorporated herein by reference to Exhibit 10.4 to Form 10-K for
Forest Oil Corporation for the year ended December 31, 1990 (File No. 0-4597).
Exhibit 10.5 Form of Executive Retirement Agreement, incorporated herein
by reference to Exhibit 10.5 to Form 10-K for Forest Oil Corporation for the
year ended December 31, 1990 (File No. 0-4597).
Exhibit 10.6 Forest Oil Corporation Stock Incentive Plan and Option
Agreement, incorporated herein by reference to Exhibit 4.1 to Form S-8 for
Forest Oil Corporation dated June 7, 1996 (File No. 0-4597).
Exhibit 10.7 Letter Agreement with Richard B. Dorn relating to a revision
to Exhibit 10.5, incorporated herein by reference to Exhibit 10.11 to Form
10-K for Forest Oil Corporation for the year ended December 31, 1991 (File
No. 0-4597).
Exhibit 10.8 Form of Executive Severance Agreement, incorporated herein
by reference to Exhibit 10.9 to Form 10-K for Forest Oil Corporation for the
year ended December 31, 1993 (File No. 0-4597).
Exhibit 10.9 Shareholders Agreement dated as of July 27, 1995 between
Forest Oil Corporation and The Anschutz Corporation incorporated herein by
reference to Exhibit 99.7 to Form 8-K for Forest Oil Corporation dated
October 11, 1995 (File No. 0-4597).
Exhibit 10.10 Shareholders Agreement dated as of January 24, 1996 between
Forest Oil Corporation and Joint Energy Development Investments Limited
Partnership, incorporated herein by reference to Exhibit 10.12 to Form 10-K
for Forest Oil Corporation for the year ended December 31, 1995 (File No.
0-4597).
*Exhibit 21 List of Subsidiaries of the Registrant.
*Exhibit 23 Consent of KPMG Peat Marwick LLP
*Exhibit 24 Powers of Attorney of the following Officers and Directors:
Philip F. Anschutz, Robert S. Boswell, William L. Britton, Cortlandt S.
Dietler, William L. Dorn, Jordan L. Haines, David H. Keyte, James H. Lee, J.
J. Simmons, III, Craig D. Slater, Joan C. Sonnen, Drake S. Tempest, Michael
B. Yanney.
*Exhibit 27.1 Financial Data Schedule - Fiscal Year 1997
*Exhibit 27.2 Fiancial Data Schedule - Q1, Q2, Q3 - 1997
*Exhibit 27.3 Fiancial Data Schedule - Q1, Q2, Q3 - 1996, and Fiscal Years
1996 and 1995
- --------------------
90
* filed herewith.
(b) Reports on Form 8-K
No reports on Form 8-K were filed by Forest during the last quarter of
1997.
91
SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
FOREST OIL CORPORATION
(Registrant)
Date: March 30, 1998 By: /s/ Daniel L. McNamara
------------------------------------
Daniel L. McNamara
Secretary
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant in the capacities and on the dates indicated.
Signatures Title Date
---------- ---- ----
Robert S. Boswell* President and Chief Executive Officer March 30, 1998
(Robert S. Boswell) (Principal Executive Officer)
David H. Keyte* Executive Vice President and March 30, 1998
(David H. Keyte) Chief Financial Officer
(Principal Financial Officer)
Joan C. Sonnen* Controller March 30, 1998
(Joan C. Sonnen) (Principal Accounting Officer)
Philip F. Anschutz* Directors of the Registrant March 30, 1998
(Philip F. Anschutz)
Robert S. Boswell*
(Robert S. Boswell)
William L. Britton*
(William L. Britton)
Cortlandt S. Dietler*
(Cortlandt S. Dietler)
William L. Dorn*
(William L. Dorn)
Jordan L. Haines*
(Jordan L. Haines)
James H. Lee*
(James H. Lee)
J. J. Simmons, III*
(J. J. Simmons, III)
Craig D. Slater*
(Craig D. Slater)
Drake S. Tempest*
(Drake S. Tempest)
Michael B. Yanney*
(Michael B. Yanney)
*By /s/ Daniel L. McNamara March 30, 1998
---------------------------
Daniel L. McNamara
(as attorney-in-fact for
each of the persons indicated)
92