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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, 1996
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
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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 $328,556,000 as of February 28, 1997 (based on
the last sale price of such stock as quoted on the NASDAQ National Market).
There were 32,557,469 shares of the registrant's Common Stock, Par Value
$.10 Per Share outstanding as of February 28, 1997.
Document incorporated by reference: Proxy Statement of Forest Oil
Corporation relative to the Annual Meeting of Shareholders to be held on May 14,
1997, 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 13
Item 3. Legal Proceedings 19
Item 4. Submission of Matters to a Vote of Security Holders 20
Item 4A. Executive Officers of Forest 20
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters 22
Item 6. Selected Financial and Operating Data 24
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 26
Item 8. Financial Statements and Supplementary Data 36
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 36
PART III
Item 10. Directors and Executive Officers of the Registrant 78
Item 11. Executive Compensation 78
Item 12. Security Ownership of Certain Beneficial Owners and Management 78
Item 13. Certain Relationships and Related Transactions 78
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 78
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 Gulf
of Mexico, Texas, Oklahoma and Alberta, Canada. Approximately 60% of total
1996 production was in the United States and approximately 40% was in Canada.
The Company currently operates 45 offshore platforms in the Gulf of Mexico,
and 1996 production from this area accounted for approximately 42% 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, 1996 Forest had 243 employees,
of whom 179 were salaried and 64 were hourly.
OPERATING STRATEGY
The Company's objective is to increase value through sustained profitable
growth of its oil and gas reserves and production by pursuing a combined
strategy of focused acquisitions, exploration and development, while reducing
operating and financial risk. The Company intends to focus its activity
onshore and offshore in the Gulf Coast of the U.S. and in the Western
Sedimentary Basin both in the U.S. and in Canada. In recent years, the
Company has grown primarily by acquiring reserves with exploitation
potential, increasing production from existing fields and exploration of its
undeveloped acreage.
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
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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 481 BCFE at December 31, 1996 of
which approximately 70% were natural gas reserves. This represents an
increase of 60% compared to estimated proved reserves of 301 BCFE at December
31, 1995 of which approximately 79% was natural gas.
Forest has dedicated an increased percentage of its capital expenditure
budget to exploration activities in 1997. The Company participates in
exploration activities through selective drilling for its own account, as
well as through farmout arrangements in certain circumstances. Forest was
successful at both 1996 federal offshore sales and at the March 1997 sale.
The Company acquired one block at the central (Louisiana) sale in April 1996
and five blocks at the western (Texas) sale in September 1996. The Company
was high bidder on eight blocks at the March 1997 central sale, although the
leases have not been formally awarded as of March 20, 1997. Forest has also
re-established its exploration effort in the Western Sedimentary Basin of the
U.S. and Canada.
Throughout the remainder of 1997, the Company also intends to continue to
pursue its strategy of acquiring additional reserves that satisfy its
investment criteria and are within the limits of its capital constraints.
Forest continues to evaluate potential acquisitions, as well as various types
of business combinations and joint ventures.
The Company's operating strategy also includes exploitation activities in the
areas of reservoir management and development drilling. Reservoir management
involves the effort to enhance value by a combination of reduced costs and
the use of techniques such as workovers to increase hydrocarbon recovery.
The Company engages in development drilling for additional reserves that
offset existing production with the objective of either increasing the
density in which wells are drilled or extending reservoirs. The Company
believes that it can increase production from, and otherwise enhance the
value of, existing fields by utilizing its technical expertise to undertake
selective workovers, recompletions and development drilling.
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. 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, 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.
Prior to 1996, the Company was not able to exploit the full potential of its
acquisitions due to financial constraints resulting from its highly leveraged
capital structure and low natural gas prices. During 1995, the Company sold
equity securities to The Anschutz Corporation (Anschutz) for $45,000,000 and
restructured $62,400,000 of indebtedness to Joint Energy Development
Investments Limited Partnership (JEDI), a Delaware limited partnership the
general partner of which is an affiliate of Enron Corp. (Enron). In December
1995, the Company agreed to exchange 1,680,000 shares of common stock for
$22,400,000 of JEDI indebtedness and warrants to acquire Forest common stock.
In January 1996, the Company completed the purchase of Canadian Forest using
the proceeds of a common stock offering and approximately $8,300,000 of
borrowings under its bank credit facility. Forest also established a
$60,000,000 CDN credit facility secured by the oil and gas properties of
Canadian Forest. As a result of these transactions, the Company has improved
its financial flexibility significantly. The Company believes such improved
financial flexibility should allow Forest to exploit its expanded property
base more effectively. During the remainder of 1997, the Company intends to
expand its exploration effort as well as pursue its acquisition and
exploitation strategy. For further information concerning the Company's
acquisitions and operations, see Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations and the Consolidated
Financial Statements and Notes thereto.
2
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 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 1997, approximately 94% 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 remainder of the Company's U.S. natural gas was
committed to both interstate and intrastate natural gas pipeline companies,
primarily under volumetric production payment agreements and long-term
contracts. 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, Canadian Forest's natural gas production is sold primarily through
the ProMark Netback Pool. 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 81% of its natural gas production through
the Netback Pool in 1996.
The Netback Pool gas sales in 1996 averaged 125 MMCF per day, of which
Canadian Forest supplied approximately 35 MMCF per day or 28%. Approximately
12% of the volumes sold in the Netback Pool in 1996 were sold at fixed prices
under long-term contracts. 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 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 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.
Substantially all of Forest's oil production in the U.S. and Canada is sold
under short-term contracts at prices which are based upon posted field
prices.
For information concerning sales to major customers, see Note 14 of Notes to
Consolidated Financial Statements.
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.
3
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. 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, assuming it is upheld in
its entirety, 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
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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.
Last year, 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 and other appeals remain pending, 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. While any additional FERC
action on these matters would affect the Company only indirectly, these
policy statements and proposed rule changes are intended to further enhance
competition in natural gas markets. The Company cannot predict what action
the FERC will take on these matters, nor can it predict whether the FERC's
actions will achieve its stated goal of increasing competition in natural gas
markets. However, the Company does not believe that it will be treated
materially differently than other natural gas producers and markets with
which it competes.
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 will be
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 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.
5
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.
The MMS has issued a notice of proposed rulemaking in which it proposes to
amend its regulations governing the calculation of royalties and the
valuation of natural gas produced from federal leases. The principal feature
in the amendments, as proposed, would establish an alternative market-index
based method to calculate royalties on certain natural gas production sold to
affiliates or pursuant to non-arm's-length sales contracts. The MMS has
proposed this rulemaking to facilitate royalty valuation in light of changes
in the gas marketing environment. The Company cannot predict what action the
MMS will take on these matters, nor can it predict at this stage of the
rulemaking proceeding how the Company might be affected by amendments to the
regulations.
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 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.
Additional proposals and proceedings that might affect the oil and gas
industry are pending before 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.
6
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 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 Government of Canada
through the NEB. 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. 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 NEB license and Canadian federal government approval.
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,
(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 per cubic
meter, and 25%, at prices above $210 per cubic meter. The ARTC rate is
applied to a maximum of $2,000,000 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.
7
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.
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 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, at least two separate courts have recently 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.
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.
Environmental legislation in Alberta has undergone a major revision and has
been consolidated into the ENVIRONMENTAL PROTECTION AND ENHANCEMENT ACT.
Under the new Act, environmental standards and compliance for releases,
clean-up and reporting are stricter. Also, the range of enforcement actions
available and the severity of penalties have been significantly increased.
These changes will have an incremental effect on the cost of conducting
operations in Alberta.
Although the Company maintains insurance against some, but not all, of the
risks described above, including insuring the costs of clean-up operations,
public liability and physical damage, there is no assurance that such
insurance will be adequate to 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
8
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 AND RISK FACTORS
Certain of the statements set forth under "Item 1. - Business" and "Item 7
- -Management's Discussion and Analysis of Financial Condition and Results of
Operations" and elsewhere in this Form 10-K, such as the statements regarding
planned capital expenditures and the availability of capital resources to
fund capital expenditures are forward-looking and are based upon the
Company's current belief as to the outcome and timing of such future events.
There are numerous risks and uncertainties that can affect the outcome and
timing of such events, including many factors beyond the control of the
Company. These factors include, but are not limited to, the matters
described below. Should one or more of these risks or uncertainties occur,
or should underlying assumptions prove incorrect, the Company's actual
results and plans for 1997 and beyond could differ materially from those
expressed in the forward-looking statements.
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 is subject to the following risk factors.
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 nonrecourse
production-based financing. 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 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, 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.
VOLATILITY OF NATURAL GAS PRICES. The Company's revenues, profitability and
future rate of growth, if any, are substantially dependent upon prevailing
prices for oil and natural gas and the ability of the Company to discover or
acquire proved reserves. Historically, the prices for oil and natural gas
have been quite volatile. The Company anticipates that such markets will
continue to be volatile over the next year. The Company is impacted more by
natural gas prices than by oil prices, because the majority of its production
is natural gas. At December 31, 1996 70% of the Company's estimated proved
reserves consisted of natural gas on an Mcfe basis. During 1996, 72% of the
Company's total production consisted of natural gas. The volatility of the
spot market for natural gas is due to factors beyond the Company's control,
including seasonality of demand which may cause the price received for spot
market natural gas to vary significantly between seasonal periods. Prices
are also affected by actions of state and local agencies, the United States
and foreign governments, and international cartels, all of
9
which are beyond the Company's control. These external factors and the
volatile nature of the energy markets make it difficult to estimate future
prices of oil and natural gas. Any substantial or extended decline in the
price of oil or natural gas would have a material adverse effect on the
Company's financial condition and results of operations.
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. Long-term contracts entered into by the Netback Pool and
the volumetric production payment agreements that the Company has entered
into further minimize the price volatility to which the Company is subject.
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, 12 and 13 of Notes to Consolidated Financial Statements.
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 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 or
governmental action cause an abrogation of, or the Company voluntarily
cancels, long-term contracts for its natural gas. Although the Company did
not have a writedown in 1996 or 1995, the Company had a writedown of
$58,000,000 in 1994. No assurance can be given that the Company will not
experience additional writedowns in the future. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
Note 18 of Notes to Consolidated Financial Statements.
GAS MARKETING. The Company's operations include gas marketing as a result of
the Canadian Forest acquisition. ProMark's gas marketing operations consist
of the marketing of its own gas production, the purchase and direct sale of
third parties' natural gas, the handling of transportation and operations of
such 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.
GAS PROCESSING. As a result of the Canadian Forest acquisition, the
Company's operations include processing of natural gas to extract various
natural gas liquids. Canadian Forest's gas processing operations primarily
consist of an interest in an ethane extraction plant located near Edmonton,
Alberta. In order to obtain from natural gas suppliers volumes of committed
natural gas reserves to maintain natural gas throughput at optimal levels,
the plant must periodically contract to process additional natural gas
volumes provided from new or existing sources. There can be no assurance
that the Company will be successful in contracting additional natural gas to
maintain optimal levels of throughput.
CREDIT RISK. ProMark 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 endeavors to offset its gas purchase or sales commitments with
other gas purchase or sales contracts, thereby limiting its exposure to price
risk.
10
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.
CURRENCY RISK. Following the acquisition of Canadian Forest in January 1996,
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
prices. The results of such Canadian operations will therefore be subject to
the risks of fluctuation in the relative values of Canadian and U.S. dollars.
GENERAL RISKS OF OIL AND GAS OPERATIONS. The nature of the oil and gas
business involves a variety of risks, including, but not limited to, the
risks of operating hazards such as fires, explosions, cratering, blow-outs,
adverse weather conditions, pollution, environmental hazards such as oil
spills, gas leaks, ruptures and discharges of toxic gases, encountering
formations with abnormal pressures and, in horizontal wellbores, the
increased risk of mechanical failure and collapsed holes, the occurrence of
any of which could result in substantial losses to the Company. The Company
conducts a substantial portion of its operations offshore in the Gulf of
Mexico. Such operations are subject to certain risks including, but not
limited to, capsizing, collision, sinking and grounding of rigs and vessels
and adverse weather and sea conditions. These risks could result in
substantial losses to the Company due to personal injury or loss of life,
severe damage or destruction of property and equipment, pollution or other
environmental damage clean-up costs, regulatory investigation and penalties
and the suspension of operations. The Company maintains insurance against
some, but not all, of these risks in amounts that management believes to be
reasonable and in accordance with customary oil and gas industry practices.
The occurrence of a significant event, however, that is not fully insured
could have a material adverse effect on the Company's financial condition and
results of operations.
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 discounted, if any, would
necessarily be greater than the Company would have discovered without its
current inventory of seismic surveys.
ACQUISITION RISKS. The Company's 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.
11
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.
SEASONALITY OF DEMAND FOR NATURAL GAS. Demand for natural gas is highly
seasonal, with demand generally higher in the colder winter months and in hot
summer months. To date, the Company generally has been able to sell all of
its available spot market natural gas at prevailing spot market prices; thus,
the volumes sold by the Company have not fluctuated materially with
seasonality. There is no assurance, however, that the Company will be able to
continue to achieve this result.
GOVERNMENT REGULATION, ENVIRONMENTAL RISKS AND TAXES. Various aspects of the
Company's oil and natural gas operations are regulated by administrative
agencies under statutory provisions of the states and provinces where such
operations are conducted, by certain agencies of the Federal government for
operations on Federal leases and by the Canadian government. In the past,
the Federal government has regulated the prices at which oil and natural 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.
Extensive U.S., state and local laws and Canadian laws govern oil and 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. These laws, rules and
regulations may restrict the rate of oil and gas production below the rate
that would otherwise exist. The regulatory burden on the oil and 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. Although Forest's experience has been to the
contrary, there is no assurance that this will continue to be the case.
12
ITEM 2. PROPERTIES
Forest's principal reserves and producing properties are oil and gas
properties located in the Gulf of Mexico, Texas, Oklahoma and Alberta,
Canada.
RESERVES
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 18 of Notes to Consolidated Financial
Statements.
Since January 1, 1996 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, 1996, 1995 and 1994:
Net Natural Gas and Liquids Production (1)(2)
---------------------------------------------
1996 1995 (3) 1994
---- ---- ----
United States:
Natural Gas (MMCF) 28,624 33,342 48,048
Liquids (MBBLS) 1,104 1,173 1,543
Canada:
Natural Gas (MMCF) 13,872 - -
Liquids (MBBLS) 1,645 - -
(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.
(3) Does not include any production relating to the acquisition of Saxon on
December 20, 1995 as the amounts involved were not significant.
13
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, 1996, 1995 and 1994 for
Forest and its subsidiaries:
United States Canada (5)
--------------------------- ----------
1996 1995 1994 1996
------- ------ ------ -------
Average Sales Prices:
NATURAL GAS
Total production (MMCF)(1) 28,624 33,342 48,048 13,872
Sales price received (per MCF)(2) $ 2.36 1.65 1.86 1.41
Effects of energy swaps (per MCF) (3) (.23) .12 .04 (.04)
------ ------ ------ ------
Average sales price (per MCF)(2) $ 2.13 1.77 1.90 1.37
LIQUIDS:
Oil and Condensate:
Total production (MBBLS)(4) 964 1,121 1,482 1,308
Sales price received (per BBL) $ 20.03 16.36 14.97 20.64
Effects of energy swaps (per BBL)(3) (1.07) (.50) (.14) (1.82)
------ ------ ------ ------
Average sales price (per BBL) $ 18.96 15.86 14.83 18.82
Natural gas liquids:
Total production (MBBLS) 140 52 61 337
Average sales price (per BBL) $ 10.48 15.81 14.79 11.87
Total liquids production (MBBLS) 1,104 1,173 1,543 1,645
Average sales price (per BBL) $ 17.88 15.86 14.83 17.40
Average production cost (per MCFE)(6) $ .56 .56 .39 .52
(1) Total natural gas production includes scheduled deliveries under volumetric
production payments, net of royalties, of 3,168 MMCF, 9,120 MMCF, and
16,005 MMCF in 1996, 1995 and 1994, respectively. Natural gas delivered
pursuant to volumetric production payment agreements represented
approximately 7%, 27% and 33% of total natural gas production in 1996, 1995
and 1994, respectively. For further information concerning volumes and
prices recorded under volumetric production payments, see Notes 6 and 14 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 15 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 12,741 MMCF,
10,146 MMCF and 12,184 MMCF for the years ended December 31, 1996, 1995 and
1994, respectively. Hedged oil and condensate volumes were 895,600
barrels, 498,000 barrels and 370,000 barrels for 1996, 1995 and 1994,
respectively. The aggregate gains (losses) under energy swap agreements
were $(10,422,000), $3,536,000 and $1,810,000, respectively, for the years
ended December 31, 1996, 1995 and 1994.
(4) An immaterial amount of oil production is covered by scheduled deliveries
under volumetric production payments.
14
(5) Alberta's royalty program was restructured in 1994 and remained uncertain
throughout much of 1995 and 1996. Canadian production of natural gas
liquids for the year ended December 31, 1996 was reduced by 79,000 barrels
as a result of royalty adjustments, resulting in an increase in the
reported average sales price for natural gas liquids in Canada to $11.87
per barrel from $9.44 or by approximately 26%. The royalty adjustments did
not have a significant effect on reported volumes or average sales prices
for natural gas or oil and condensate. Canadian Forest continues to
receive additional information with respect to royalty calculations and
anticipates that revisions to such calculations will continue to occur
throughout 1997. The effects of future royalty adjustments cannot be
predicted at this time.
(6) 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.
PRODUCTIVE WELLS
The following summarizes total gross and net productive wells of the Company
and its subsidiaries at December 31, 1996:
Productive Wells (1)
------------------------
United States Canada
------------- ------
Gross (2)
Gas 278 379
Oil 180 566
----- -----
Totals (3) 458 945
----- -----
----- -----
Net (4)
Gas 100.7 127.0
Oil 118.5 225.9
----- -----
Totals 219.2 352.9
----- -----
----- -----
(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 27 dual completions in the United States and 20 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.
15
DEVELOPED AND UNDEVELOPED ACREAGE
Forest and its subsidiaries held acreage as set forth below at December 31,
1996 and 1995. 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. A portion of the developed acreage is also
subject to production payments. See Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations and Notes 5 and 6
of Notes to Consolidated Financial Statements.
Developed Acreage (1) Undeveloped Acreage (2)
--------------------- -----------------------
Gross (3) Net (4) Gross (3) Net (4)
--------- ------- --------- -------
United States:
Louisiana offshore 145,549 58,662 53,212 20,774
Oklahoma 63,334 21,710 7,504 1,396
Texas onshore 123,959 61,529 15,813 8,394
Texas offshore 45,382 22,694 40,347 31,694
Wyoming 8,517 4,484 51,076 21,343
Other 26,304 10,959 6,114 1,773
------- ------- ------- -------
413,045 180,038 174,066 85,374
Canada
Alberta 323,451 111,907 234,625 123,480
Other 61,301 41,191 283,124 43,731
------- ------- ------- -------
384,752 153,098 517,749 167,211
------- ------- ------- -------
Total acreage at
December 31, 1996 797,797 333,136 691,815 252,585
------- ------- ------- -------
------- ------- ------- -------
Total acreage at
December 31, 1995 496,480 211,615 172,354 83,006
------- ------- ------- -------
------- ------- ------- -------
(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.
During 1996, the Company's gross and net developed acreage increased
approximately 61% and 57%, respectively, and gross and net undeveloped
acreage increased approximately 301% and 204%, respectively. The increases
were due primarily to the purchase of Canadian Forest.
Approximately 29% of the Company's total net undeveloped acreage is under
leases that have terms expiring in 1997, if not held by production, and
another approximately 8% of net undeveloped acreage will expire in 1998 if
not also held by production.
16
DRILLING ACTIVITY
Forest and its subsidiaries owned interests in gross and net exploratory and
development wells for the years ended December 31, 1996, 1995 and 1994 as set
forth below. This information does not include wells drilled under farmout
agreements.
United States Canada
-------------------- ------
1996 1995 1994 1996
---- ---- ---- ----
Gross Exploratory Wells:
Dry (1) 4 3 2 4
Productive (2) 9 1 2 2
--- --- --- ----
13 4 4 6
--- --- --- ----
--- --- --- ----
Net Exploratory Wells:(3)
Dry (1) 2.0 1.3 2.0 2.9
Productive (2) 3.5 .3 1.3 1.4
--- --- --- ----
5.5 1.6 3.3 4.3
--- --- --- ----
--- --- --- ----
Gross Development Wells:
Dry (1) 3 - - 4
Productive (2) 15 6 5 70
--- --- --- ----
18 6 5 74
--- --- --- ----
--- --- --- ----
Net Development Wells:(3)
Dry (1) .5 - - .9
Productive (2) 1.9 .6 2.1 19.9
--- --- --- ----
2.4 .6 2.1 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 1996, eleven development wells and one exploratory well were drilled in the
United States under farmout agreements. Nine of the development wells were
productive and two were dry holes. The exploratory well was a dry hole. In
Canada, twelve development wells and five exploratory wells were drilled in 1996
under farmout agreements. Ten of the development wells were productive and two
were dry holes. Three of the exploratory wells were productive and two were dry
holes.
17
PRESENT ACTIVITIES
At December 31, 1996 Forest and its subsidiaries had four development wells
that were in the process of being drilled. Two wells (both in Canada) were
determined to be productive in 1997 and two wells (one in the U.S. and one in
Canada) were determined to be dry holes. An additional development well was
being drilled in Canada under a farmout agreement. This well was
subsequently determined to be productive.
DELIVERY COMMITMENTS
At December 31, 1996 Forest and its subsidiaries were obligated to deliver,
or to make cash settlement with respect to, approximately 4 BCF of natural
gas under the terms of volumetric production payments. The delivery
commitments cover approximately 9% of the estimated net proved reserves of
natural gas attributable to the subject properties. The production payments
are nonrecourse to other properties owned by the Company. For further
information concerning the Company's volumetric production payment
agreements, see Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations and Notes 6 and 18 of Notes to
Consolidated Financial Statements. The Company is further obligated to
deliver approximately .6 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, 1996 the ProMark Netback
Pool had entered into fixed price contracts to sell approximately 10.7 BCF of
natural gas in 1997 at an average price of $1.66 per MCF and approximately
5.4 BCF of natural gas in 1998 at an average price of approximately $1.88 per
MCF. Canadian Forest is obligated to deliver approximately 25% of the volumes
of natural gas subject to these contracts.
18
ITEM 3. LEGAL PROCEEDINGS
Royalty owners had filed two separate class action lawsuits against the
Company in the State District Court of Caddo County, Oklahoma. In each case
the plaintiff alleged unjust enrichment, breach of fiduciary duty,
constructive fraud and breach of contract. The claims in both suits were
based on the allegation that the Company underpaid royalties on the
consideration received pursuant to settlement agreements with ONEOK, Inc. in
1990 and 1992.
MODRALL V. FOREST OIL CORPORATION, Case No. CJ-95-67, was filed on March 24,
1995, and the Court, on September 13, 1995, certified a class comprised of
the royalty and overriding royalty owners in the three wells involved in the
1992 ONEOK, Inc. settlement. MERCO OF OKLAHOMA, INC. V. FOREST OIL
CORPORATION, Case No. CJ-95-230, was filed on September 27, 1995. This suit
involves the 1990 ONEOK, Inc. settlement. The plaintiffs in both suits
sought actual damages in excess of $10,000, punitive damages in excess of
$10,000, an accounting, interest and costs. There had been no specific
determination of the amount in controversy in either case.
The plaintiffs alleged in both cases that they were entitled to share in all
value received by the Company under the aforesaid settlements, including
proceeds not attributable to actual gas production. As a result of a ruling
by the Oklahoma Supreme Court in a case involving similar issues, both of
these cases were dismissed without prejudice on September 12, 1996.
The Company entered into a Settlement Agreement and Release with El Paso
Natural Gas Company ("El Paso"), effective May 15, 1987, which was later
modified by a Partial Termination of Settlement Agreement and Release and Gas
Purchase Agreement, effective January 1, 1989. These agreements settled the
parties' disputes concerning take-or-pay deficiencies under eight gas
purchase contracts covering 16 wells located in Washita County, Oklahoma.
The Company received a demand letter dated November 22, 1995 from the same
attorney who represented Modrall and Merco, on behalf of a royalty owner in
one of the wells covered by the El Paso settlements. A class action petition
was filed January 19, 1996 in WRIGHT v. FOREST OIL CORPORATION, et al., Case
No. CJ-96-6 in the State District Court of Washita County, Oklahoma. Like
the plaintiffs in the MODRALL and MERCO cases, the plaintiff in this case
contended that Forest underpaid royalties on the consideration it received
under the El Paso settlement. He asserted claims for breach of contract,
unjust enrichment, breach of fiduciary duty, constructive fraud and bad faith
breach of contract, and sought an accounting and an unspecified amount of
actual and punitive damages, interest and costs. This case was also dismissed
without prejudice on September 12, 1996 for the same reasons as set forth
above.
A Petition for Rehearing asking the Oklahoma Supreme Court to reconsider its
ruling in the related case was denied.
The Company, in the ordinary course of business, is a party to various other
legal actions. In the opinion of management, none of these actions, or those
discussed above, either individually or in the aggregate, will have a
material adverse effect on the Company's financial condition, liquidity or
results of operations.
19
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* 48 25 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.
Robert S. Boswell* 47 11 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 Executive Committee. Director
of C.E. Franklin Ltd. and Saxon Petroleum
Inc.
David H. Keyte 40 9 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.
Bulent A. Berilgen 48 12 Vice President and Chief Technical Officer
since May 1996. Prior thereto Vice President
of Operations from December 1993 to May 1996.
Prior thereto Vice President - Engineering
and Development since January 1992. Director
of Saxon Petroleum Inc.
Forest D. Dorn 42 19 Vice President-Gulf Coast Region since August
1996. Vice President from February 1991 and
General Business Manager from December 1993
to August 1996. Prior thereto General
Manager - Operations since January 1992.
20
Years with
Name (A) Age Forest Office (B)
- ---------------- --- ---------- ----------
Neal A. Stanley 49 - Vice President - Western Region since August
1996. Prior thereto President of Teton Oil
and Gas Corporation.
V. Bruce Thompson 49 2 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.
Kenton M. Scroggs 44 13 Vice President since December 1993 and prior
thereto Treasurer. Member of the Company's
Employee Benefits Committee.
Daniel L. McNamara 51 25 Secretary and Corporate Counsel. Member of
the Company's Employee Benefits Committee.
Joan C. Sonnen 43 7 Controller since December 1993. Prior
thereto Director of Financial Accounting and
Reporting.
____________
*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.
21
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 January 5, 1996,
the Company's shareholders approved a reverse stock split of the Common Stock.
The reverse stock split resulted in the reclassification of each five shares of
Common Stock outstanding into one share.
On February 28, 1997 32,557,469 shares of Common Stock were held by 1,745
holders of record.
Forest's Common Stock is 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 as reported by the Nasdaq National Market are listed in
the chart below. All of the following quotations have been adjusted to
reflect the 5 to 1 reverse stock split of the Common Stock that occurred on
January 8, 1996. There were no dividends on Common Stock in 1995, 1996 or in
the first quarter of 1997.
High Low
---- ---
1995
----
First Quarter $ 12-3/16 $ 6-7/8
Second Quarter 11-7/8 7-3/16
Third Quarter 15-5/8 8-1/8
Fourth Quarter 16-9/16 10-5/8
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 (through
February 28) $ 19-3/8 $ 13-1/4
$.75 CONVERTIBLE PREFERRED STOCK
The Company called for redemption on February 28, 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; 2,783,945 shares or 96.7% of the shares
outstanding were converted into Forest's Common Stock. The remaining 93,728
preferred shares that were not tendered for conversion were redeemed by
Forest at the redemption price of $10.06 per share (at a total cost to Forest
of $942,904). Lehman Brothers Inc. purchased 65,616 shares of Forest Oil
Common Stock to fund the cash requirement of the redemption in accordance
with the terms of its standby purchase agreement with Forest.
22
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
Forest's 11 1/4% Senior Subordinated Notes due September 1, 2003, and (iii)
the Company's Second Amended and Restated Credit Agreement dated January 31,
1997 with The Chase Manhattan Bank (Chase), as agent for a group of banks
(the Credit Facility), 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 15, 1997.
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.
RECENT SALES OF UNREGISTERED SECURITIES
On August 1, 1996 the Company issued 2,250,000 shares of Common Stock to
Anschutz pursuant to the exercise of an option at a price of $11.64 per
share. On November 5, 1996 the Company issued Anschutz 388,888 shares of
Common Stock pursuant to the exercise of a warrant at a price of $10.50 per
share. On November 5, 1996 the Company issued 2,000,000 shares of Common
Stock to JEDI for the extinguishment of approximately $43,000,000 of debt.
These transactions were exempt from registration under the Securities Act of
1933 (the 33 Act) pursuant to Section 4(2) of the 33 Act. On November 5,
1996 Anschutz also acquired 1,240,000 shares of Common Stock pursuant to the
conversion of 620,000 shares of the Company's Second Series Preferred Stock
in a transaction exempt from registration pursuant to Section 3(a)(9) of the
33 Act.
23
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, 1996. 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,
-----------------------------------------------------
1996 1995 1994 (1) 1993 1992 (2)
---- ---- -------- ---- -------
(In Thousands Except per Share Amounts and Volumes)
FINANCIAL DATA
Revenue:
Marketing and processing $187,374 - - - -
Oil and gas sales 128,713 82,275 114,541 102,883 99,239
Miscellaneous, net 1,387 181 1,406 2,265 13,947
-------- ------- ------- ------- -------
Total revenue $317,474 82,456 115,947 105,148 113,186
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
Earnings (loss) before income
taxes, cumulative effects of
changes in accounting principles
and extraordinary items $ 6,590 (18,003) (67,844) (10,705) 11,286
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
Net earnings (loss) $ 3,305 (17,996) (81,843) (21,213) 7,298
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
Weighted average number of common
shares outstanding 27,163 7,360 5,619 4,399 2,755
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
Net earnings (loss) attributable to
common stock $ 1,147 (20,156) (84,004) (23,463) 4,950
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
Primary earnings (loss) per share: (3)
Earnings (loss) attributable to common
stock before cumulative effects
of changes in accounting principles
and extraordinary items $ (.04) (2.74) (12.46) (2.64) 1.80
Cumulative effect of changes in
accounting principles - - (2.49) (.26) -
Extraordinary items .08 - - (2.44) -
-------- ------- ------- ------- -------
Net earnings (loss) attributable to
common stock $.04 (2.74) (14.95) (5.34) 1.80
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
Total assets $563,458 321,043 324,832 426,755 378,532
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
Long-term debt $168,859 193,879 207,054 194,307 168,321
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
Other long-term liabilities $ 53,560 27,139 28,166 27,053 15,285
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
Deferred revenue $ 7,591 15,137 35,908 67,228 67,066
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
Shareholders' equity $242,443 44,297 6,086 88,156 59,881
-------- ------- ------- ------- -------
-------- ------- ------- ------- -------
24
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA (CONTINUED)
Years Ended December 31,
-----------------------------------------------------
1996 1995 1994 (1) 1993 1992 (2)
---- ---- -------- ---- -------
(In Thousands Except per Share Amounts and Volumes)
OPERATING DATA
Annual production (4):
Gas (MMCF) 42,496 33,342 48,048 41,114 29,174
Liquids (MBBLS) 2,749 1,173 1,543 1,493 1,450
Average price received (4):
Gas (per MCF) (5) $ 1.89 1.77 1.90 1.88 1.70
Liquids (per Barrel) $ 17.59 15.86 14.83 16.97 18.14
Capital expenditures, net of asset sales $234,556 44,913 29,839 168,169 81,695
Proved Reserves (4) (6):
Gas (MMCF) 337,250 238,128 246,996 273,382 194,655
Liquids (MBBLS) 24,014 10,541 7,532 8,198 7,560
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves (6) $559,869 256,917 207,549 262,176 190,971
Total discounted future net cash flows
relating to proved oil and gas reserves,
including amounts attributable to
volumetric production payments (6) $562,995 265,393 230,149 299,053 227,009
- -------------------
(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) Financial data for the year ended December 31, 1992 include the effects of
a gas contract settlement, which increased total revenue by $37,541,000 and
net earnings by $24,043,000 or $8.73 per share. The average price received
for natural gas for the year ended December 31, 1992 excludes the effects
of the settlement.
(3) Fully diluted earnings (loss) per share was the same as primary earnings
(loss) per share in all years except 1992. In 1992, fully diluted earnings
per share was $1.45.
(4) Includes amounts attributable to required deliveries under volumetric
production payments. See Notes 6 and 18 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 15 of Notes to Consolidated Financial Statements.
(6) The 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.
25
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
NET EARNINGS (LOSS). Net earnings for 1996 were $3,305,000 compared to a net
loss of $17,996,000 in 1995. Earnings for the 1996 period include an
extraordinary gain on extinguishment of debt of $2,166,000. 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 Oil Ltd. (Canadian Forest), which were completed
in December 1995 and January 1996, respectively, and to the contribution made by
Forest's Canadian marketing and processing subsidiary (ProMark), which was
also acquired in January 1996. The net loss for 1995 was $17,996,000
compared to a net loss of $81,843,000 in 1994. The 1995 loss was primarily
due to decreased oil and natural gas volumes and lower natural gas prices,
offset by $4,263,000 of income associated with a gas contract settlement.
The 1994 loss included a $58,000,000 writedown of the book value of the
Company's oil and gas properties due to a ceiling test limitation and a
charge of $13,990,000 relating to the change in the method of accounting for
oil and gas sales from the sales method to the entitlements method. See
"Accounting Policies".
REVENUE. Total revenue increased 285% to $317,474,000 in 1996 from
$82,456,000 in 1995 and decreased 29% in 1995 from $115,947,000 in 1994. The
significant increase in total revenue in 1996 is due primarily to the
acquisitions of ProMark, Canadian Forest and Saxon.
Marketing and processing revenue attributable to the marketing activities of
ProMark subsequent to its purchase on January 31, 1996 was $187,374,000. For
the eleven months ended December 31, 1996 ProMark marketed approximately 851
MMCF of natural gas per day.
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 sales revenue decreased to $82,275,000 in 1995 from $114,541,000 in
1994, or by approximately 28%. In 1995, natural gas and oil production volumes
were down 31% and 24%, respectively, compared to 1994. These decreases resulted
primarily from limited capital expenditures in 1994 and 1995 that did not allow
the Company to replace existing production through acquisitions and drilling.
The average sales price for natural gas in 1995 decreased 7% compared to 1994,
exclusive of the effects of the income associated with the gas contract
settlement. The average sales price for oil in 1995 increased 7% compared to
1994.
Oil and gas sales to Enron and certain of its affiliates (Enron Affiliates),
the Company's largest customer, represented approximately 25% of oil and gas
sales in 1996, compared to 38% in 1995 and 51% in 1994. The decreases during
these periods are attributable primarily to the decreases in delivery
requirements pursuant to volumetric production payments. In addition, the
Company's spot market sales to Enron Affiliates increased to approximately 11
BCFE in 1996 from approximately 8 BCFE in 1995 as a result of higher
production volumes available for sale. Spot market sales to Enron Affiliates
in 1994 were approximately 16 BCFE.
26
The production volumes and average sales prices for the years ended December
31, 1996, 1995 and 1994 for Forest and its subsidiaries were as follows:
Years Ended December 31,
----------------------------
1996 (5) 1995 1994
-------- ---- ----
NATURAL GAS
Total production (MMCF)(1) 42,496 33,342 48,048
Sales price received (per MCF)(2) $ 2.06 1.65 1.86
Effects of energy swaps (per MCF)(3) (.17) .12 .04
------ ------ ------
Average sales price (per MCF)(2) $ 1.89 1.77 1.90
LIQUIDS
Oil and condensate:
Total production (MBBLS)(4) 2,272 1,121 1,482
Sales price received (per BBL) $20.38 16.36 14.97
Effects of energy swaps (per BBL)(3) (1.50) (.50) (.14)
------ ------ ------
Average sales price (per BBL) $18.88 15.86 14.83
Natural gas liquids:
Total production (MBBLS) 477 52 61
Average sales price (per BBL) $11.46 15.81 14.79
Total liquids production (MBBLS) 2,749 1,173 1,543
Average sales price (per BBL) $17.59 15.86 14.83
- -------------------
(1) Total natural gas production includes scheduled deliveries under volumetric
production payments, net of royalties, of 3,168 MMCF, 9,120 MMCF and 16,005
MMCF in 1996, 1995 and 1994, respectively. Natural gas delivered pursuant
to volumetric production payment agreements represented approximately 7%,
27% and 33% of total natural gas production in 1996, 1995 and 1994,
respectively. For further information concerning volumes and prices
recorded under volumetric production payments, see Notes 6 and 18 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 15 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 12,741 MMCF,
10,146 MMCF and 12,184 MMCF for the years ended December 31, 1996, 1995 and
1994, respectively. Hedged oil and condensate volumes were 895,600
barrels, 498,000 barrels and 370,000 barrels for the years ended December
31, 1996, 1995 and 1994, respectively. The aggregate gains (losses) under
energy swap agreements were $(10,422,000), $3,536,000 and $1,810,000,
respectively, for the years ended December 31, 1996, 1995 and 1994.
(4) An immaterial amount of oil production is covered by scheduled deliveries
under volumetric production payments.
(5) Alberta's royalty program was restructured in 1994 and remained uncertain
throughout much of 1995 and 1996. Production of natural gas liquids for
the year ended December 31, 1996 was reduced by 79,000 barrels as a result
of royalty adjustments, resulting in an increase in the reported average
sales price for natural gas liquids to $11.46 per barrel from $9.70 or by
approximately 18%. The royalty adjustments did not have a significant
effect in reported volumes or average sales prices for natural gas or oil
and condensate. Canadian Forest continues to receive additional
information with respect to royalty calculations and anticipates that
revisions to such calculations will continue to occur throughout 1997. The
effects of future royalty adjustments cannot be predicted at this time.
Miscellaneous net revenue 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. Miscellaneous net revenue was $181,000 in 1995.
Miscellaneous net revenue of $1,406,000 in 1994 included income from the sale
of miscellaneous pipeline systems and equipment and the reversal of an
accounts receivable reserve, partially offset by a reserve for settlement of
a
27
royalty dispute and a payment of deferred maintenance costs of a real
estate complex formerly used for general business purposes.
MARKETING AND PROCESSING EXPENSE. In 1996, marketing and processing expense
of $178,706,000 was recorded which relates primarily to the marketing
activities of ProMark subsequent to its purchase on January 31, 1996.
OIL AND GAS PRODUCTION EXPENSE. 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 production expense increased slightly to $22,463,000 in 1995
from $22,384,000 in 1994. On an MCFE basis, however, production expense
increased to $.56 per MCFE in 1995 from $.39 per MCFE in 1994. The increased
cost per MCFE from 1994 to 1995 is directly attributable to fixed components
of oil and gas production expense being allocated over a smaller production
base.
GENERAL AND ADMINISTRATIVE EXPENSE. 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. General and administrative
expense decreased 19% to $9,081,000 in 1995 compared to $11,166,000 in 1994
due primarily to a reduction in the size of the Company's workforce on March
1, 1995. The capitalization rate was approximately 36% in 1996 compared to
43% in 1995 and 40% in 1994. 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 $21,396,000 in 1996, $15,857,000 in 1995 and $18,719,000 in 1994.
Total overhead costs were approximately 35% higher in 1996 compared to 1995
due primarily to the addition of the Canadian operations, which increased
Forest's salaried workforce to 179 at December 31, 1996 compared to 115 at
December 31, 1995. Total overhead costs were approximately 15% lower in 1995
than in 1994. The Company's salaried workforce in the United States was 115
at December 31, 1995 compared to 143 at December 31, 1994. The decreases in
total overhead costs and personnel in 1995 were due primarily to a reduction
in the size of the Company's workforce effective March 1, 1995. The
following table summarizes the total overhead costs incurred during the
periods:
Years Ended December 31,
------------------------
1996 1995 1994
---- ---- ----
(In Thousands)
Overhead costs capitalized $ 7,773 6,776 7,553
General and administrative costs expensed (1) 13,623 9,081 11,166
------- ------ ------
Total overhead costs $21,396 15,857 18,719
------- ------ ------
------- ------ ------
(1) Includes $2,555,000 in 1996 related to marketing and processing operations.
INTEREST EXPENSE. 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. Interest expense of
$25,323,000 in 1995 decreased $1,450,000 or 5% compared to 1994 due primarily
to lower effective interest rates related to the nonrecourse secured loan and
the dollar denominated production payment.
DEPRECIATION AND DEPLETION EXPENSE. 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 in
the United States due to expected increased costs for services. Depreciation
and depletion expense decreased 33%
28
to $43,592,000 in 1995 from $65,468,000 in 1994 due to decreased production,
as well as a decrease in the depletion rate per unit of production. The
depletion rate decreased to $1.06 per MCFE for United States production in
1995 compared to $1.13 in 1994 due to writedowns of the Company's oil and gas
properties taken in the third and fourth quarters of 1994.
At December 31, 1996 the Company had undeveloped properties with a cost basis
of approximately $30,046,000 in the U.S. and $13,870,000 in Canada which were
excluded from depletion compared to $28,380,000 in the U.S. at December 31,
1995 and $30,441,000 in the U.S. at December 31, 1994. The increase in 1996
compared to 1995 is due primarily to the acquisition of undeveloped
properties in the Canadian Forest purchase.
IMPAIRMENT OF OIL AND GAS PROPERTIES. The Company was not required to record
a writedown of the carrying value of its oil and gas properties in 1996 or
1995. The Company recorded a writedown of its oil and gas properties of
$58,000,000 in 1994 due primarily to a decrease in spot market prices for
natural gas.
The average Gulf Coast spot price received by the Company for natural gas
decreased from $3.89 per MCF at December 31, 1996 to approximately $1.80 per
MCF at March 1, 1997. The West Central Texas Intermediate price for crude oil
decreased from $23.75 per barrel at December 31, 1996 to approximately $18.00
per barrel at March 1, 1997. The average spot price received for Canadian
natural gas production decreased from $2.76 per MMBTU at December 31, 1996 to
approximately $1.82 per MMBTU at March 1, 1997. The Canadian spot price
received for crude oil decreased from $25.92 per barrel at December 31, 1996
to approximately $20.30 per barrel at March 1, 1997.
Writedowns of the full cost pools in the United States and Canada may be
required if the depressed price environment persists, undeveloped property
values decrease, estimated proved reserve volumes are revised downward or
costs incurred in exploration, development, or acquisition activities exceed
the discounted future net cash flows from the additional reserves, if any.
ACCOUNTING POLICIES. The Company changed its method of accounting for oil
and gas sales from the sales method to the entitlements method effective
January 1, 1994. Under the sales method previously used by the Company, all
proceeds from production credited to the Company were recorded as revenue
until such time as the Company had produced its share of related reserves.
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. Under the entitlements method, the
Company records a receivable or payable to the extent it receives less or
more than its proportionate share of the related revenue. The Company
believes that the entitlements method is preferable because it allows for
recognition of revenue based on the Company's actual share of jointly owned
production and provides a better matching of revenue and related expenses.
The cumulative effect of the change for the periods through December 31,
1993, was a charge of $13,990,000. The effect of this change on 1994 was an
increase in earnings from operations of $3,584,000 and an increase in
production volumes of 1,555,000 MCF. There were no related income tax
effects in 1994.
In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets to Be Disposed Of" (SFAS No. 121). Oil and gas properties
accounted for under the full cost method of accounting are excluded from the
scope of SFAS No. 121, but will continue to be subject to the ceiling test
limitation. SFAS No. 121 requires that impairment losses be recorded on
other long-lived assets used in operations when indicators of impairment are
present and either the undiscounted future cash flows estimated to be
generated by those assets or the fair market value are less than the assets'
carrying amount. SFAS No. 121 also addresses the accounting for long-lived
assets that are expected to be disposed of. The Company adopted SFAS No. 121
effective January 1, 1996. The adoption of SFAS No. 121 had no effect on the
Company's financial statements.
29
Statement of Financial Accounting Standards No. 123, "Accounting for Stock
Based Compensation" (SFAS No. 123), was issued by the Financial Accounting
Standards Board in October 1995. SFAS No. 123 establishes financial
accounting and reporting standards for stock-based employee compensation
plans as well as transactions in which an entity issues its equity
instruments to acquire goods or services from non-employees. The Company
adopted SFAS No. 123 effective January 1, 1996, and will continue to use the
measurement method prescribed by APB Opinion 25, as permitted under SFAS No.
123. The Company has included the pro forma disclosures required by SFAS No.
123 in Note 9 of Notes to Consolidated Financial Statements.
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 nonrecourse production-based financing.
In 1995, the Company completed a series of transactions with Anschutz and
JEDI. For total consideration of $45,000,000, the Company issued to Anschutz
3,760,000 shares of Common Stock, 620,000 shares of a new series of
convertible preferred stock and a warrant that entitled Anschutz to purchase
3,888,888 shares of Common Stock for $10.50 (the A Warrant). The Company
restructured JEDI's existing loan, which had a principal balance of
approximately $62,368,000 before unamortized discount of $4,984,000, into two
tranches: a $40,000,000 tranche and an approximately $22,400,000 tranche. In
consideration for the loan restructuring JEDI received a warrant to purchase
2,250,000 shares of Common Stock at $10.00 per share (the B Warrant). JEDI
granted an option to Anschutz (the Anschutz Option) to purchase from JEDI
shares purchased pursuant to the B Warrant at an escalating price ranging from
$10.00 to $15.50 per share. In December 1995, JEDI exchanged the $22,400,000
tranche and the B Warrant for 1,680,000 shares of Common Stock. In connection
with this 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.
30
In 1996, the Company completed additional transactions that improved its
financial position considerably. 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 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 in cash to extinguish approximately
$43,000,000 of nonrecourse secured debt owed to JEDI. The JEDI debt bore
interest at 12-1/2% per annum. 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 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 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 November 14, 1996 the Company filed a shelf registration 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.
31
On February 7, 1997 the Company called for redemption all 2,877,673 shares of
its $.75 Convertible Preferred Stock. This conversion eliminated all
outstanding preferred stock from Forest's capital structure. 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,
1996 deadline. The remaining 93,728 preferred shares that were not tendered
for conversion 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 the Company's common stock to fund
the cash requirement of the redemption in accordance with the terms of its
standby purchase agreement with Forest. Redemption of the $.75 Convertible
Preferred Stock eliminates approximately $2,200,000 of annual preferred
dividend payments.
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.
CASH FLOW. Historically, one of the Company's primary sources of capital has
been net cash provided by operating activities (operating cash flow). The
following summary table reflects comparative cash flow data for the Company
for the years ended December 31, 1996, 1995 and 1994.
Years Ended December 31,
------------------------
1996 1995 1994
---- ---- ----
(In Thousands)
Net cash provided (used) by operating
activities $ 67,815 (3,062) 42,441
Net cash used by investing activities (226,867) (17,219) (32,307)
Net cash provided (used) by financing
activities 164,500 20,698 (14,126)
Net cash provided by operating activities increased to $67,815,000 in 1996
compared to a net use of cash for operating activities of $3,062,000 in 1995,
due to higher natural gas and liquids prices, increased natural gas and
liquids production as a result of the Saxon and Canadian Forest acquisitions
and the contribution made by ProMark and an increase in accounts payable
during 1996. The Company used $226,867,000 for investing activities in 1996
compared to $17,219,000 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 $164,500,000 in 1996 compared to
$20,698,000 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.
32
CAPITAL EXPENDITURES. The Company's expenditures for property acquisition,
exploration and development for the past three years were as follows:
Years Ended December 31,
----------------------------
1996 1995 1994
---- ---- ----
(In Thousands)
Property acquisition costs (1):
Proved properties $140,875 26,487 9,553
Undeveloped properties 18,080 320 209
-------- ------ -----
158,955 26,807 9,762
Exploration costs:
Direct costs 40,831 11,528 15,229
Overhead capitalized 2,608 1,211 464
-------- ------ -----
43,439 12,739 15,693
Development costs:
Direct costs 36,559 7,633 10,000
Overhead capitalized 5,165 5,565 7,089
-------- ------ -----
41,724 13,198 17,089
-------- ------ -----
$244,118 52,744 42,544
-------- ------ -----
-------- ------ -----
(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 1997 budgeted direct expenditures for exploration and
development are approximately $64,000,000 and $61,000,000, respectively.
Capitalized overhead in 1997 is expected to be approximately $8,000,000. The
Company expects to be able to meet its 1997 capital expenditure financing
requirements using cash flows generated by operations, sales of non-strategic
assets and borrowings under existing lines of credit. However, there can be
no assurance 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. The prices the Company receives for its future oil and natural gas
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.
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.
PENDING ACQUISITION:
On March 4, 1997 Saxon announced an offer to purchase all of the issued and
outstanding Class A shares of Truax Resources Corporation (Truax). Truax
shareholders may elect to receive either $2.06 CDN or two Saxon shares for
each Truax share tendered, subject to certain minimum and maximum aggregate
amounts of Saxon shares. The value of the offer is approximately $38,000,000
CDN. The offer expires April 8, 1997 and is subject to a minimum of
two-thirds of the outstanding Class A shares of Truax being tendered and the
receipt of necessary regulatory approvals. Truax has recommended that its
shareholders do not tender shares pursuant to the Saxon offer. Assuming that
the tender offer is successful, Forest currently intends to exercise its
rights under its equity participation agreement with Saxon to purchase
additional shares to maintain its majority ownership position in Saxon.
33
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. 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, 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.
BANK CREDIT FACILITIES. Under the Credit Facility with Chase, as amended,
the Company may borrow up to $60,000,000 for working capital and/or general
corporate purposes. The borrowing base is subject to formal redeterminations
semi-annually, but may be changed at the banks' discretion at any time.
The Credit Facility is secured by a lien on, and a security interest in, a
majority of the Company's U.S. proved oil and gas properties and related
assets (subject to prior security interests granted to holders of volumetric
production payment agreements) and a pledge of accounts receivable. The
maturity date of the Credit Facility is January 31, 2000. Under the terms of
the Credit Facility, the Company is 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. At December 31, 1996
the outstanding balance under this facility was $26,400,000. The Company has
also used the facility for a $1,500,000 letter of credit.
On February 8, 1996 a newly-formed Canadian subsidiary of Forest entered into
a credit agreement (the Canadian Credit Facility) with The Chase Manhattan
Bank of Canada for the benefit of Canadian Forest and ProMark. The borrowing
base under the Canadian Credit Facility is $60,000,000 CDN. The borrowing
base is subject to formal redeterminations semi-annually, but may be changed
by the bank at its discretion at any time. The maturity date of the Canadian
Credit Facility is February 7, 1999. The Canadian Credit Facility is
indirectly secured by substantially all the assets of Canadian Forest. Funds
drawn under the Canadian Credit Facility can be used for general corporate
purposes. Under the terms of the Canadian Credit Facility, the three
Canadian subsidiaries 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. At December 31, 1996 the
outstanding balance under this facility was $32,500,000 (US). The Company
has also used this facility for a letter of credit in the amount of
$3,081,000 CDN.
In addition to the credit facilities described above, Saxon has a revolving
credit facility with a borrowing base of $20,000,000 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, 1996
there were no outstanding borrowings under this facility.
At February 28, 1997 the amount outstanding under the Credit Facility was
$34,600,000, the amount outstanding under the Canadian Credit Facility was
$33,622,000 and the amount outstanding under the Saxon revolving credit
facility was $7,821,000.
WORKING CAPITAL. The Company had a working capital deficit of approximately
$12,649,000 at December 31, 1996 compared to a deficit of approximately
$9,181,000 at December 31, 1995. The increase in the deficit is attributable
primarily to an increase in accounts payable related to exploration and
development activities.
The Company generally reports a working capital deficit at the end of a period.
The working capital deficit is 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
34
long-term bank credit facilities. For cash management purposes, drawdowns on
the credit facilities are not made until the due dates of the payables.
At December 31, 1996 the Company had available borrowing capacity of
approximately $60,000,000 under its long-term bank credit facilities. The
Company's available credit at December 31, 1996 was adequate to fund the
working capital deficit at that date.
LONG-TERM SALES CONTRACTS. A significant portion of Canadian Forest's
natural gas production is sold through the ProMark Netback Pool. At December
31, 1996 the ProMark Netback Pool had entered into fixed price contracts to
sell approximately 10.7 BCF of natural gas in 1997 at an average price of
$1.66 CDN per MCF and approximately 5.4 BCF of natural gas in 1998 at an average
price of approximately $1.88 CDN per MCF. Canadian Forest is obligated to
deliver approximately 25% of the volumes of natural gas subject to these
contracts.
HEDGING PROGRAM. In addition to the volumes of natural gas and oil sold
under long-term sales contracts and dedicated to volumetric production
payments, 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, 1996 the Company had
natural gas swaps and collars for an aggregate of approximately 27.0 BBTU
(billion British Thermal Units) per day of natural gas during 1997 at fixed
prices ranging from $1.159 per MMBTU (million British Thermal Units) on an
Alberta Energy Company "C" (AECO "C") basis to $2.728 per MMBTU on a New York
Mercantile Exchange (NYMEX) basis and an aggregate of approximately 3.2 BBTU
per day of natural gas during 1998 at fixed prices ranging from $1.159 (AECO
"C" basis) to $2.540 (NYMEX basis) per MMBTU. The weighted average hedged
price for natural gas under such agreements is $2.15 and $2.18 per MMBTU in
1997 and 1998, respectively. Subsequent to December 31, 1996 the Company
entered into a collar to hedge 7.0 BBTU of natural gas per day from April
1997 to September 1997. The floor and ceiling price of the collar are $2.10
and $2.50 per MMBTU (NYMEX basis), respectively. At December 31, 1996 the
Company had oil swaps for an aggregate of 1,964 barrels per day of oil during
1997 at fixed prices ranging from $17.90 to $21.05 (NYMEX basis). The
weighted average hedged price for oil under such agreements is $19.77 per
barrel. Subsequent to December 31, 1996, the Company entered into an oil
swap to hedge 200 barrels of oil per day from February 1997 to July 1997 at a
fixed price of $23.67 per barrel (NYMEX basis). The Company also entered into
a 1998 oil swap to hedge 247 barrels per day from January 1998 to December 1998
at a fixed price of $20.00 per barrel (NYMEX basis). For further information on
the Company's outstanding energy swaps, see Note 13 of Notes to Consolidated
Financial Statements.
35
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.
36
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, 1996 and 1995, 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, 1996.
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, 1996 and 1995, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 1996 in conformity with generally
accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, the Company
changed its method of accounting for oil and gas sales from the sales method
to the entitlements method effective January 1, 1994.
KPMG PEAT MARWICK LLP
Denver, Colorado
February 12, 1997
37
FOREST OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
-----------------
1996 1995
---- ----
(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 8,626 3,287
Accounts receivable 55,462 17,395
Other current assets 4,996 2,557
-------- -------
Total current assets 69,084 23,239
Net property and equipment, at cost, full cost
method (Notes 5 and 6) 458,242 277,599
Investment in affiliate (Note 4) - 11,301
Goodwill and other intangible assets, net 29,439 -
Other assets 6,693 8,904
-------- -------
$563,458 321,043
-------- -------
-------- -------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Cash overdraft $ 4,682 2,055
Current portion of long-term debt (Note 5) 2,091 2,263
Accounts payable 64,811 17,456
Accrued interest 4,584 4,029
Other current liabilities 5,565 6,617
-------- -------
Total current liabilities 81,733 32,420
Long-term debt (Notes 3 and 5) 168,859 193,879
Other liabilities 19,844 27,139
Deferred revenue (Note 6) 7,591 15,137
Deferred income taxes 33,716 -
Commitments and contingencies (Notes 10, 12 and 13)
Minority interest (Note 2) 9,272 8,171
Shareholders' equity (Notes 2, 3, 5, 8 and 9):
Preferred stock 15,827 24,359
Common stock, 30,541,105 shares in
1996 (10,660,291 shares in 1995) 3,053 1,066
Capital surplus 438,556 241,241
Common shares to be issued in debt restructuring - 6,073
Accumulated deficit (214,190) (217,495)
Foreign currency translation (803) (1,407)
Treasury stock, at cost, none in 1996 and
1,060,000 shares in 1995 - (9,540)
-------- -------
Total shareholders' equity 242,443 44,297
-------- -------
$563,458 321,043
-------- -------
-------- -------
See accompanying Notes to Consolidated Financial Statements
38
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31,
--------------------------------
1996 1995 1994
-------- ------- -------
(In Thousands Except Per Share Amounts)
Revenue:
Marketing and processing $187,374 - -
Oil and gas sales:
Gas 80,111 59,084 91,309
Gas contract settlement (Note 15) - 4,263 -
Oil, condensate and natural gas
liquids 48,602 18,928 23,232
-------- ------- -------
Total oil and gas sales 128,713 82,275 114,541
Miscellaneous, net 1,387 181 1,406
-------- ------- -------
Total revenue 317,474 82,456 115,947
Expenses:
Marketing and processing 178,706 - -
Oil and gas production 32,199 22,463 22,384
General and administrative 13,623 9,081 11,166
Interest 23,307 25,323 26,773
Depreciation and depletion 63,068 43,592 65,468
Minority interest in loss of
subsidiary (19) - -
Provision for impairment of oil
and gas properties - - 58,000
-------- ------- -------
Total expenses 310,884 100,459 183,791
-------- ------- -------
Earnings (loss) before income taxes,
cumulative effect of change in
accounting principle and extraordinary
item 6,590 (18,003) (67,844)
Income tax expense (benefit) (Note 7):
Current 3,943 (7) 9
Deferred 1,508 - -
-------- ------- -------
5,451 (7) 9
-------- ------- -------
Earnings (loss) before cumulative
effect of change in accounting principle
and extraordinary item 1,139 (17,996) (67,853)
Cumulative effect of change in accounting
principle for oil and gas sales (Note 1) - - (13,990)
-------- ------- -------
Earnings (loss) before extraordinary
item 1,139 (17,996) (81,843)
Extraordinary item - gain on
extinguishment of debt (Note 3) 2,166 - -
-------- ------- -------
Net earnings (loss) $3,305 (17,996) (81,843)
-------- ------- -------
-------- ------- -------
Weighted average number of common
shares outstanding 27,163 7,360 5,619
-------- ------- -------
-------- ------- -------
Earnings (loss) attributable to
common stock $ 1,147 (20,156) (84,004)
-------- ------- -------
-------- ------- -------
Primary and fully diluted earnings
(loss) per common share:
Loss attributable to common stock
before cumulative effect of change
in accounting principle and
extraordinary item $ (.04) (2.74) (12.46)
Cumulative effect of change in
accounting principle - - (2.49)
-------- ------- -------
Loss attributable to common stock
before extraordinary item (.04) (2.74) (14.95)
Extraordinary item - gain on
extinguishment of debt .08 - -
-------- ------- -------
Earnings (loss) attributable
to common stock $ .04 (2.74) (14.95)
-------- ------- -------
-------- ------- -------
See accompanying Notes to Consolidated Financial Statments
39
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, 1993 $ 15,845 565 195,977 - (117,656) (785) (5,790)
Net loss - - - - (81,843) - -
Exercise of employee stock options (Note 9) - 1 104 - - - -
$.75 Convertible Preferred Stock
dividends paid in cash (Note 8) - - (2,161) - - - -
Treasury stock contributed to the Retire-
ment Savings Plan and other (Note 10) - - (1,583) - - - 3,964
Foreign currency translation - - - - - (552) -
------- ------- -------- ----- --------- ------- -------
Balance December 31, 1994 15,845 566 192,337 - (199,499) (1,337) (1,826)
Net loss - - - - (17,996) - -
Issuance of Common Stock to
Anschutz (Note 3) - 376 27,796 - - - -
Issuance of Second Series Convertible
Preferred Stock to Anschutz (Notes 3 and 8) 8,518 - - - - - -
Issuance of warrants to Anschutz (Notes 3 and 9) - - 8,310 - - - -
Issuance of warrants 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 and treasury
stock contributed 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 - -
ISSUANCE OF COMMON STOCK, NET OF OFFERING
COSTS AND MINORITY INTEREST EFFECT OF
$706,000 (NOTE 9) - 1,214 124,613 - - - 9,540
COMMON SHARES ISSUED IN JEDI
EXCHANGE (NOTE 3) - 168 5,905 (6,073) - - -
EXERCISE OF ANSCHUTZ OPTION (NOTES 3 AND 9) - 225 25,962 - - - -
EXERCISE OF ANSCHUTZ A WARRANT (NOTES 3 AND 9) - 39 4,044 - - - -
ISSUANCE OF COMMON STOCK TO JEDI (NOTE 3) - 200 26,736 - - - -
EXERCISE OF PUBLIC WARRANTS (NOTE 9) - 2 334 - - - -
CONVERSION OF SECOND SERIES PREFERRED
STOCK TO COMMON STOCK (NOTE 8) (8,518) 124 8,394 - - - -
EXERCISE OF EMPLOYEE STOCK OPTIONS (NOTE 9) - 3 398 - - - -
COMMON STOCK ISSUED AND TREASURY
STOCK CONTRIBUTED 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) -
------- ------- -------- ----- --------- ------- -------
------- ------- -------- ----- --------- ------- -------
See accompanying Notes to Consolidated Financial Statements
40
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31,
1996 1995 1994
---- ---- ----
(In Thousands)
Cash flows from operating activities:
Earnings (loss) before cumulative effect of change in
accounting principle and extraordinary item $ 1,139 (17,996) (67,853)
Adjustments to reconcile loss before cumulative effect of
change in accounting principle and extraordinary item
to net cash provided (used) by operating activities:
Depreciation and depletion 63,068 43,592 65,468
Amortization of deferred debt costs 1,253 1,015 1,029
Provision for impairment of oil and gas properties - - 58,000
Deferred income tax expense 1,508 - -
Interest added to principal 3,059 574 2,205
Minority interest in net loss of subsidiary (19) - -
Other, net 792 1,714 2,033
(Increase) decrease in accounts receivable (17,441) 4,285 4,839
(Increase) decrease in other current assets (921) (152) 1,078
Increase (decrease) in accounts payable 19,417 (11,458) 4,021
Increase (decrease) in accrued interest and other
current liabilities 3,506 (3,865) 2,941
Proceeds from volumetric production payments - - 4,353
Amortization of deferred revenue (7,546) (20,771) (35,673)
-------- ------- --------
Net cash provided (used) by operating activities 67,815 (3,062) 42,441
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 (108,332) (27,098) (42,780)
Proceeds from sales of assets 17,875 8,715 12,941
Increase (decrease) in other assets, net (58) 2,285 (2,468)
-------- ------- --------
Net cash used by investing activities (226,867) (17,219) (32,307)
Cash flows from financing activities:
Proceeds from bank borrowings 194,018 82,600 31,500
Repayments of bank borrowings (176,641) (91,800) (23,500)
Proceeds from nonrecourse secured loan - - 1,400
Repayments of nonrecourse secured loan (13,881) (1,143) -
Repayments of production payment obligation (3,622) (2,316) (2,771)
Redemptions and repurchases of subordinated debentures
and secured notes - - (7,171)
Proceeds from common stock offering, net of offering
costs 136,073 - -
Proceeds from exercise of warrants and options 31,945 - 105
Proceeds from capital stock and warrants issued, net - 41,060 -
Payment of preferred stock dividends (1,079) (540) (2,161)
Debt issuance costs (3) (491) (772)
Increase (decrease) in cash overdraft 2,627 (2,390) 551
Decrease in other liabilities, net (4,937) (4,282) (11,307)
-------- ------- --------
Net cash provided (used) by financing activities 164,500 20,698 (14,126)
Effect of exchange rate changes on cash (109) 1 (88)
-------- ------- --------
Net increase (decrease) in cash and cash equivalents 5,339 418 (4,080)
Cash and cash equivalents at beginning of year 3,287 2,869 6,949
-------- ------- --------
Cash and cash equivalents at end of year $ 8,626 3,287 2,869
-------- ------- --------
-------- ------- --------
Cash paid during the year for:
Interest $ 15,040 22,138 23,989
-------- ------- --------
-------- ------- --------
Income taxes $ 3,428 - 9
-------- ------- --------
-------- ------- --------
See accompanying Notes to Consolidated Financial Statements
41
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(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 1996, the Company's oil and gas
operations were conducted in the United States and in Canada. During 1995 and
1994, 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, 1996, 1995 and 1994, there were undeveloped property costs of
$30,046,000, $28,380,000 and $30,441,000, respectively, which were not being
depleted in the United States and costs of $13,870,000 which were not being
depleted in Canada. Of the undeveloped costs in the United States not being
depleted at December 31, 1996, approximately 46% were incurred in 1996, 9% in
1995, 3% in 1994, 40% in 1993 and 2% in 1992. All of the undeveloped properties
in Canada not being depleted at December 31, 1996 were acquired 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
------------- ------
1994 $1.13 -
1995 1.06 -
1996 1.12 .85
42
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(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. As a result of this limitation on capitalized costs, the
accompanying financial statements include a provision for impairment of oil and
gas property costs of $58,000,000 in the United States in 1994.
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:
1996 1995
---- ----
(In Thousands)
Oil and gas properties $1,457,212 1,216,027
Buildings, transportation and
other equipment 10,993 10,502
---------- ---------
1,468,205 1,226,529
Less accumulated depreciation,
depletion and valuation allowance 1,009,963 948,930
---------- ---------
$ 458,242 277,599
---------- ---------
---------- ---------
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, 1996:
1996
----
(In Thousands)
Goodwill $16,728
Gas marketing contracts 14,594
-------
31,322
Less accumulated amortization 1,883
-------
$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.
OIL AND GAS SALES - The Company changed its method of accounting for oil and gas
sales from the sales method to the entitlements method effective January 1,
1994. Under the sales method previously used by the Company, all proceeds from
production credited to the Company were recorded as revenue until such time as
the Company had produced its share of related reserves. 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.
43
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED):
- -------------------------------------------------------------------------------
Under the entitlements method, the Company records a receivable or payable to
the extent it receives less or more than its proportionate share of the related
revenue. The Company believes that the entitlements method is preferable
because it allows for recognition of revenue based on the Company's actual share
of jointly owned production and provides a better matching of revenue and
related expenses.
The cumulative effect of the change for the periods through December 31, 1993
was a charge of $13,990,000. The effect of this change on 1994 was an increase
in earnings from operations of $3,584,000 and an increase in production volumes
of 1,555,000 MCF. There were no related income tax effects in 1994.
As of December 31, 1996 the Company had produced approximately 2.6 BCF more than
its entitled share of production. The estimated value of this imbalance of
approximately $4,355,000 is included in the accompanying consolidated balance
sheet as a short-term liability of $1,650,000 and a long-term liability of
$2,705,000.
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. Gains and
losses related to these hedging transactions are recognized as adjustments to
therevenue recorded for the related production. Costs associated with the
purchase of certain hedging instruments are 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.
EARNINGS (LOSS) PER SHARE - Primary earnings (loss) per share is computed by
dividing net earnings (loss) attributable to common stock by the weighted
average number of common shares and common share equivalents outstanding during
each period, excluding treasury shares. Net earnings (loss) attributable to
common stock represents net earnings (loss) less preferred stock dividend
requirements of $2,158,000 in 1996, $2,160,000 in 1995 and $2,161,000 in 1994.
Common share equivalents include, when applicable, dilutive stock options and
warrants using the treasury stock method.
Fully diluted earnings (loss) per share is computed assuming, in addition to the
above, (i) that convertible preferred stock was converted at the beginning of
each period or date of issuance, if later, and (ii) any additional dilutive
effect of stock options and warrants. The effects of these assumptions were
anti-dilutive in 1996, 1995 and 1994.
RECLASSIFICATIONS - Certain amounts in prior years' financial statements have
been reclassified to conform to the 1996 financial statement presentation.
44
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(2) ACQUISITIONS:
- -------------------------------------------------------------------------------
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, 15,500,000 convertible preferred shares and
warrants to purchase 5,300,000 common shares. The preferred shares and the
nonvoting common shares of Saxon are convertible into voting common shares at
any time. 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 on
Forest's consolidated balance sheet 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.
Subsequent to December 31, 1996 Forest converted its preferred shares of
Saxon into 27,192,983 nonvoting common shares and purchased 3,158,142 voting
common shares and 2,380,608 nonvoting common shares of Saxon pursuant to an
equity participation agreement. These transactions increased Forest's
economic interest in Saxon to 66%.
On January 31, 1996 the Company completed the acquisition of 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).
45
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(2) ACQUISITIONS (CONTINUED):
- -------------------------------------------------------------------------------
The consolidated balance sheet of Forest includes the accounts of Saxon and
Canadian Forest at December 31, 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. The
following unaudited pro forma consolidated statements of operations information
assumes that the Common Stock offering and the acquisitions of Saxon and
Canadian Forest occurred as of January 1, 1995:
Pro Forma Year Ended December 31,
---------------------------------
1996 1995
---- ----
(In Thousands Excluding Per Share Amounts)
Revenue:
Marketing and processing $ 200,715 139,444
Oil and gas sales 132,423 129,326
Miscellaneous, net 1,387 132
--------- -------
Total revenue $ 334,525 268,902
--------- -------
--------- -------
Earnings (loss) before income taxes,
and extraordinary item $ 7,512 (9,680)
--------- -------
--------- -------
Net earnings (loss) $ 3,687 (15,972)
--------- -------
--------- -------
Primary earnings (loss) per share $ .06 (.81)
--------- --------
--------- --------
Fully diluted earnings (loss) per share $ .05 (.81)
--------- --------
--------- --------
(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 additional
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. The loan
carried interest 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.
46
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(3) ANSCHUTZ AND JEDI TRANSACTIONS (CONTINUED):
- -------------------------------------------------------------------------------
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 ultimate disposition of the shares. The fair value of the Common
Stock issued and the cash paid to JEDI, including
47
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(3) ANSCHUTZ AND JEDI TRANSACTIONS (CONTINUED):
- -------------------------------------------------------------------------------
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.
(4) INVESTMENT IN AFFILIATE:
- -------------------------------------------------------------------------------
In 1992, the Company sold its Canadian assets and related operations to CanEagle
resources corporation (CanEagle) for approximately $51,250,000 in Canadian funds
($41,000,000 U.S.). In the transaction, the Company received cash of
approximately $28,000,000 CDN ($22,400,000 U.S.), net of expenses, and provided
financing in the aggregate principal amount of $22,000,000 CDN ($17,600,000
U.S.). 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 $6,124,000 CDN ($4,400,000 U.S.) 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 1992 and 1994
transactions as reductions 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, 1995 or 1994.
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:
1996 1995
---- ----
Credit facility $ 26,400 23,800
Canadian Forest credit facility 32,500 -
Saxon credit facility - 16,437
Nonrecourse secured loan - 40,322
Production payment obligation 12,596 16,218
11-1/4% Senior Subordinated Notes 99,421 99,365
-------- --------
170,917 196,142
Less current portion (2,058) (2,263)
-------- --------
Long-term debt $168,859 193,879
-------- --------
-------- --------
CREDIT FACILITY:
The Company has a secured credit facility (the Credit Facility) with The Chase
Manhattan Bank, NA. (Chase) as agent for a group of banks. Under the Credit
Facility, as amended, the Company may borrow up to $60,000,000 for working
capital and/or general corporate purposes. Advances under this facility bear
interest at rates ranging from the banks' prime rate to prime plus 3/4% or,
alternatively, the London interbank offered rate (LIBOR) plus 1.0% to LIBOR plus
1 3/4% depending on the ratio of debt to total capitalization for the Company.
The borrowing base is subject to formal redetermination semi-annually, but may
be changed at the banks' discretion at any time.
48
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(5) LONG-TERM DEBT (CONTINUED):
- -------------------------------------------------------------------------------
The Credit Facility is secured by a lien on, and a security interest in, a
majority of the Company's domestic proved oil and gas properties and related
assets (subject to prior security interests granted to holders of volumetric
production payment agreements) and a pledge of accounts receivable. The
maturity date of the Credit Facility is January 31, 2000. Under the terms of
the Credit Facility, the Company is 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 on capital stock and reporting responsibilities. At December 31, 1996
notes payable of $26,400,000 were outstanding under the Credit Facility with
interest at rates ranging from 7.00% to 8.75% per annum. The Company has also
used the Credit Facility for a $1,500,000 letter of credit.
CANADIAN FOREST CREDIT FACILITY:
On February 8, 1996 a newly-formed Canadian subsidiary of Forest entered into a
credit agreement (the Canadian Credit Facility) with The Chase Manhattan Bank of
Canada for the benefit of Canadian Forest and ProMark. The borrowing base under
the Canadian Credit Facility is $60,000,000 CDN. The borrowing base is subject
to formal redeterminations semi-annually, but may be changed by the bank at its
discretion at any time. The maturity date of the Canadian Credit Facility is
February 7, 1999. The Canadian Credit Facility is indirectly secured by
substantially all the assets of Canadian Forest. Funds drawn under the Canadian
Credit Facility can be used for general corporate purposes. Under the terms of
the Canadian Credit Facility, the three Canadian subsidiaries 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. At
December 31, 1996 the outstanding balance under this facility was $32,500,000
(US) with interest at rates ranging from 7.25% to 7.3125% per annum. Canadian
Forest has entered into interest rate swaps which fix the interest rate on
approximately $22,000,000 of long-term debt at 10.055% to 10.55% with terms
expiring in 1998. The Company has also used this facility for a letter of
credit in the amount of $3,081,000 CDN.
SAXON CREDIT FACILITY:
Saxon has a revolving credit facility with a borrowing base of $20,000,000 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, 1996 there was no outstanding balance under this facility.
NONRECOURSE SECURED LOAN:
On December 30, 1993, the Company entered into a nonrecourse secured loan
agreement with JEDI. the terms of the JEDI loan were restructured in 1995 as
described in Note 3. Under the terms of the restructured JEDI loan, the Company
was required to make payments based on the net proceeds, as defined, from
certain subject properties. Payments under the JEDI loan were due monthly and
were equal to 90% of total net operating income from the secured properties,
reduced by 80% of allowable capital expenditures, as defined. On November 5,
1996 the Company exchanged 2,000,000 shares of Common Stock plus approximately
$13,500,000 cash to extinguish the remaining balance of the nonrecourse secured
debt owed to JEDI of approximately $43,000,000. See Note 3.
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, 1996
the remaining principal amount was $16,981,000 and the recorded liability was
$12,596,000. 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 retains a
management fee equal to 10% of sales from the properties, which is deducted in
the calculation of net proceeds. The Company's current estimate, based on
expected production and prices, budgeted capital expenditure levels and expected
discount amortization, is that 1997 payments will reduce the recorded liability
by approximately $2,058,000, which amount is included in current liabilities,
increase the recorded liability by
49
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(5) LONG-TERM DEBT (CONTINUED):
- -------------------------------------------------------------------------------
approximately $1,022,000 in 1998, and reduce the recorded liability by $975,000
in 1999, $2,433,000 in 2000 and $2,038,000 in 2001. 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 Senior Subordinated Notes were issued at a price of 99.259% yielding
11.375% to the holders. The Senior Subordinated Notes are redeemable at the
option of the Company, in whole or in part, at any time on or after September 1,
1998 initially at a redemption price of 105.688%, plus accrued interest to the
date of redemption, declining at the rate of 1.896% per year to September 1,
2000 and at 100% thereafter.
Under the terms of the Senior Subordinated Notes, the Company must meet
certain tests before it is able to pay cash dividends or make other
restricted payments, incur additional indebtedness, engage in transactions
with its affiliates, incur liens and engage in certain sale and leaseback
arrangements. The terms of the Senior Subordinated Notes also limit the
Company's ability to undertake a consolidation, merger or transfer of all or
substantially all of its assets. In addition, the Company is, subject to
certain conditions, obligated to offer to repurchase Senior Subordinated
Notes at par value plus accrued and unpaid interest to the date of
repurchase, with the net cash proceeds of certain sales or dispositions of
assets. Upon a change of control, as defined, the Company will be required
to make an offer to purchase the Senior Subordinated Notes at 101% of the
principal amount thereof, plus accrued interest to the date of purchase.
(6) DEFERRED REVENUE:
- --------------------------------------------------------------------------------
From April 1991 through July 1994, the Company entered into various volumetric
production payments with entities affiliated with Enron for net proceeds of
$139,058,000. Under the terms of these production payments, the Company was
required to deliver 80.1 BCF of natural gas and 770,000 barrels of oil over
periods ranging from three to eight years.
The Company is required to deliver the scheduled volumes from the subject
properties or to make a cash payment for volumes produced but not delivered,
in combination not to exceed a specified percentage of monthly production.
If production levels are not sufficient to meet scheduled delivery
commitments, the Company must account for and make up such shortages, at
market-based prices, from future production.
The Company is responsible for royalties and for production costs associated
with operating the properties subject to the production payment agreements.
The Company may grant liens on properties subject to the production payment
agreements, but it must notify prospective lienholders that their rights are
subject to the prior rights of the production payment owner.
Amounts received under the production payments were recorded as deferred
revenue. Volumes associated with amortization of deferred revenue for the
years ended December 31, 1996, 1995 and 1994 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)
----------- ------- --------- -------
1996 3,721 87 3,168 74
1995 11,045 173 9,120 145
1994 19,985 218 16,005 182
(1) Amounts settled in cash in lieu of volumes were $1,641,000, $2,433,000 and
$5,742,000 for the years ended December 31, 1996, 1995, and 1994,
respectively.
(2) Represents volumes required to be delivered to Enron affiliates net of
estimated royalty volumes.
50
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(6) DEFERRED REVENUE (CONTINUED):
- --------------------------------------------------------------------------------
Future amortization of deferred revenue, based on the scheduled deliveries under
the production payment agreements, is as follows:
Net sales volumes
Volumes required to be attributable to production
delivered to Enron payment deliveries (1)
Annual -------------------- ------------------------
Amortization Natural Gas Natural Gas
------------ (MMCF) (MMCF)
(In Thousands) ----------- -----------
1997 $ 2,439 1,410 1,008
1998 1,592 892 637
1999 1,352 757 541
Thereafter 2,208 1,237 884
------- ----- -----
$ 7,591 4,296 3,070
------- ----- -----
------- ----- -----
(1) Represents volumes required to be delivered to Enron 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:
1996 1995 1994
---- ---- ----
(In Thousands)
Tax expense (benefit) at 35% of income (loss)
before income taxes, cumulative effects of
changes in accounting principles and
extraordinary item $ 2,300 (6,367) (23,749)
Change in the valuation allowance for deferred
tax assets attributable to income (loss)
before income taxes, cumulative effects
of changes in accounting principles and
extraordinary item (367) 5,732 23,220
Canadian earnings taxed at higher effective rate 1,068 - -
Canadian Crown payments (net of
Alberta Royalty Tax Credit) not deductible
For tax purposes 2,799 - -
Canadian resource allowance (3,005) - -
Non-deductible depletion and amortization 1,694 - -
Expiration of tax carryforwards 643 535 455
Other 319 93 83
------- ---- ----
Total income tax expense (benefit) $ 5,451 (7) 9
------- ---- ----
------- ---- ----
51
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(7) INCOME TAXES (CONTINUED):
- -------------------------------------------------------------------------------
Deferred income taxes generally result from recognizing income and expenses at
different times for financial and tax reporting. In the U.S., differences
result in part from 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.
The components of the net deferred tax liability at December 31, 1996 and 1995
are as follows:
1996 1995
---- ----
(In Thousands)
Deferred tax assets:
Allowance for doubtful accounts $ 296 283
Accrual for retirement benefits 1,128 1,223
Accrual for medical benefits 2,220 2,220
Accrual for sales recorded on the entitlement
method 1,499 2,920
Accrual for interest rates swaps 509 -
Net operating loss carryforward 46,828 39,264
Depletion carryforward 6,958 6,958
Investment tax credit carryforward 2,576 3,219
Alternative minimum tax credit carryforward 2,187 2,187
Other 613 243
--------- --------
Total gross deferred tax assets 64,814 58,517
Less valuation allowance (43,999) (45,124)
--------- --------
Net deferred tax assets 20,815 13,393
Deferred tax liabilities:
Property and equipment (48,475) (13,393)
Deferred income on long term contracts (6,014) -
Other (42) -
--------- --------
Total gross deferred tax liabilities (54,531) (13,393)
--------- --------
Net deferred tax liability $(33,716) -
--------- --------
--------- --------
The net change in the total valuation allowance for the year ended December
31, 1996 was a decrease of $1,125,000, which includes a decrease in the
valuation allowance of $758,000 attributable to the extraordinary gain.
52
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(7) INCOME TAXES (CONTINUED):
- --------------------------------------------------------------------------------
The Alternative Minimum Tax (AMT) credit carryforward available to reduce
future U.S. Federal regular taxes aggregated $2,187,000 at December 31, 1996.
this amount may be carried forward indefinitely. U.S. Federal regular and
amt net operating loss carryforwards at December 31, 1996 were $133,795,000
and $130,142,000, respectively, and will expire in the years indicated below:
Regular AMT
------- ---
(In Thousands)
2000 $ 3,590 4,975
2005 8,307 -
2008 28,999 31,799
2009 22,817 22,964
2010 45,736 46,058
2011 24,346 24,346
-------- --------
$133,795 130,142
-------- --------
-------- --------
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 $2,576,000 at December 31, 1996 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, 1996. This amount may be carried forward indefinitely.
Canadian tax pools available to reduce future Canadian Federal income taxes
aggregated approximately $78,000,000 at December 31, 1996. These tax pool
balances are deductible on a declining balance basis ranging from ten to one
hundred percent of the balance annually. These 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 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.
53
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(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 and 2,880,173 shares outstanding at December
31, 1995, with an aggregate liquidation preference of $28,776,730 at December
31, 1996 and $28,801,730 at December 31, 1995. This stock was convertible at
any time, at the option of the holder, at the rate of .7 shares of Common Stock
for each share of $.75 Convertible Preferred Stock, subject to adjustment upon
occurrence of certain events. During 1996, 2,500 shares of $.75 Convertible
Preferred Stock were converted into 1,750 shares of Common Stock; during 1995,
800 shares of $.75 Convertible Preferred Stock were converted into 560 shares of
Common Stock; there were no conversions in 1994. The $.75 Convertible Preferred
Stock was redeemable, in whole or in part, at the option of the Company, after
July 1, 1996 at $10.00 per share plus accumulated and unpaid dividends.
Cumulative annual dividends of $.75 per share were payable quarterly, in
arrears, on the first day of February, May, August and November, when and as
declared. Until December 31, 1993, the Company was required to pay such
dividends in shares of Common Stock. After such date, dividends could be paid
in cash or, at the Company's election, in shares of Common Stock or in a
combination of cash and Common Stock; however, the Company was prohibited from
paying cash dividends on its $.75 Convertible Preferred Stock from the February
1, 1995 dividend through the March 8, 1996 dividend due to restrictions
contained in the Credit Facility with its lending banks. After such date,
dividends could be paid in cash or at the Company's election, in shares of
Common Stock or in a combination of cash and Common Stock. Under the terms of
the $.75 Convertible Preferred Stock, Common Stock delivered in payment of
dividends was valued for dividend payment purposes at between 75% and 90%,
depending on trading volume, of the average last reported sales price of the
Common Stock during a specified period prior to the record date for the dividend
payment. During any period in which dividends on preferred stock were in
arrears, no dividends or distributions, except for dividends paid in shares of
Common Stock, could be paid or declared on the Common Stock, nor could any
shares of Common Stock be acquired by the Company.
The Company called for redemption on February 28, 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. Each
share of Second Series Preferred Stock (1) was convertible into 2 shares of
Common Stock, (2) had no right to vote, (3) had the right to receive dividends
on the dates and in the form that dividends were payable on the Common Stock,
and (4) had the right, upon any liquidation, dissolution or winding up of the
Company, before any distribution is made on any shares of Common Stock, to be
paid the amount of $18.00 and, after there shall have been paid to each share of
Common Stock the amount of $9.00, had the right to receive distributions on the
dates and in the form that distributions are payable on the Common Stock. On
November 5, 1996 all 620,000 shares of the Company's 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.
54
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(9) COMMON STOCK (CONTINUED):
- -------------------------------------------------------------------------------
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 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 or 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 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 has outstanding the A Warrant that is 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 expires 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.
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.
55
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(9) COMMON STOCK (CONTINUED):
- -------------------------------------------------------------------------------
The following table summarizes the activity in the Company's stock-based
compensation plan for the years ended December 31, 1994, 1995 and 1996:
Weighted
Average Number of
Number of Exercise Shares
Shares Price Exercisable
--------- -------- -----------
Outstanding at December 31, 1993 610,800 $ 19.99 155,320
Granted at fair value 62,000 25.00
Exercised (7,000) 15.00
Cancelled (7,000) 25.00
--------- --------
Outstanding at December 31, 1994 658,800 20.46 372,080
Cancelled (30,800) 20.52
--------- --------
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
--------- --------
--------- --------
The fair value of each option granted in 1996 was estimated using the
Black-Scholes option pricing model with the following assumptions: 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.
56
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(9) COMMON STOCK (CONTINUED):
- --------------------------------------------------------------------------------
The following table summarizes information about options outstanding at
December 31, 1996:
Options Outstanding Options Excercisable
---------------------------------- ---------------------
Weighted
Average Weighted Weighted
Remaining Average Average
Range of Number of Contractual Exercise Number of Exercise
Exercise Price Shares Life Price Shares Price
-------------- --------- ----------- -------- --------- ---------
$11.25-12.63 666,080 9.23 $11.53 107,360 $11.59
$14.00-15.00 737,500 9.45 14.17 197,100 14.34
$25.00 58,000 5.75 25.00 58,000 25.00
------------ --------- ---- ------ ------- ------
$11.25-25.00 1,461,580 9.20 $13.37 362,460 $15.23
------------ --------- ---- ------ ------- ------
------------ --------- ---- ------ ------- ------
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 income for the year ended December 31, 1996 would have been
$2,230,000 and net earnings per share would have been less than $.01 per
share. There were no stock options granted in 1995; accordingly, no
compensation cost would have been recognized in that year.
(10) EMPLOYEE BENEFITS
- --------------------------------------------------------------------------------
PENSION PLANS:
The Company has a qualified defined benefit pension plan which covers its
U.S. 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 1996, 1995 or 1994.
The following table sets forth the Pension Plan's funded status and amounts
recognized in the Company's consolidated financial statements at December 31:
1996 1995
-------- --------
(In Thousands)
Actuarial present value of accumulated
benefit obligation (all benefits are vested) $(25,959) $(27,485)
-------- --------
-------- --------
Projected benefit obligation for service
rendered to date $(25,959) $(27,485)
Plan assets at fair market value, consisting
primarily of listed stocks, bonds and other
fixed income obligations 24,897 24,270
-------- --------
Unfunded pension liability (1,062) (3,215)
Unrecognized net loss from past experience
different from that assumed and effects
of changes in assumptions 2,012 4,133
-------- --------
Pension asset recognized in the balance sheet $ 950 $ 918
-------- --------
-------- --------
57
FORREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(10) EMPLOYEE BENEFITS (CONTINUED):
- --------------------------------------------------------------------------------
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%. For 1994 the discount rate
used in determining the actuarial present value of the projected benefit
obligation was 9% 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,
1996, 1995 and 1994 are as follows:
1996 1995 1994
------- ------- -------
(In Thousands)
Net pension expense (benefit) included the
following components:
Interest cost on projected benefit
obligation $ 1,926 $ 2,049 $ 1,976
Actual return on plan assets (3,056) (3,243) (245)
Net amortization and deferral 1,098 1,234 (1,955)
------- ------- -------
Net pension expense (benefit) $ (32) $ 40 $ (224)
------- ------- -------
------- ------- -------
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, 1996 the
projected benefit obligation under this plan totaled $604,000, 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.
In 1993, as a result of the change in the discount rate for the Pension Plan
and the supplementary retirement plan, the Company recorded a liability of
$3,038,000, representing the unfunded pension liability, and a corresponding
decrease in capital surplus. As a result of changes in the discount rate for
the Pension Plan and the supplementary retirement plan, the Company records
corresponding changes in the liability and capital surplus. In 1994, the
Company reduced the liability representing the unfunded pension liability by
approximately $1,570,000, with a corresponding increase in capital surplus.
In 1995, the Company increased the unfunded pension liability by
approximately $2,836,000, with a corresponding decrease in capital surplus.
In 1996, the Company reduced the unfunded pension liability by approximately
$2,145,000, with a corresponding increase in 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.
58
FORREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(10) EMPLOYEE BENEFITS (CONTINUED):
- --------------------------------------------------------------------------------
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:
1996
--------------
(In Thousands)
Actuarial present value of accumulated benefit obligation
(all benefits are vested) $(4,119)
-------
-------
Projected benefit obligation for service rendered to date $(4,119)
Plan assets at fair market value, consisting primarily of
listed stocks, bonds and other fixed income obligations 4,922
-------
Pension surplus 803
Unrecognized net gain from past experience different from
that assumed and effects of changes in assumptions (915)
-------
Pension liability recognized in the balance sheet $ (112)
-------
-------
For 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%.
The components of net pension expense for the year ended December 31 is as
follows:
1996
--------------
(In Thousands)
Net pension expense included the
following components:
Interest cost on projected benefit obligation $ 456
Actual return on plan assets (310)
Net amortization and deferral (69)
-------
Net pension expense $ 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 and in 1994,
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, Company contributions were made in cash. The expense
associated with the Company's contribution was $399,000 in 1996, $423,000 in
1995 and $516,000 in 1994.
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 $95,000 in 1996.
59
FORREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(10) EMPLOYEE BENEFITS (CONTINUED):
- --------------------------------------------------------------------------------
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
is 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 payable in May 1997. The Agreements for the other six
Retirees provide for supplemental retirement payments totaling approximately
$970,000 per year through 1998 and approximately $770,000 per year in 1999
and 2000.
The $2,881,000 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, $921,000 and $916,000 in 1996, 1995 and
1994, respectively, including $831,000 in each of the years 1996, 1995 and
1994 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.
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," (SFAS 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:
1996 1995
------ ------
(In Thousands)
Retired participants $4,522 $4,803
Active participants fully eligible for benefits 256 201
Other active participants 1,101 1,026
------ ------
Accumulated postretirement benefit obligation (APBO) 5,879 6,030
Plan assets at fair market value - -
------ ------
APBO in excess of plan assets 5,879 6,030
Unrecognized loss (166) (595)
------ ------
Accrued postretirement benefit liability $5,713 $5,435
------ ------
------ ------
The discount rates used in determining the actuarial present value of the
APBO at December 31, 1996, 1995 and 1994 were 7.75%, 7.25% and 9%,
respectively.
60
FORREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(10) EMPLOYEE BENEFITS (CONTINUED):
- --------------------------------------------------------------------------------
The components of postretirement benefit expense for the years ended December
31, 1996, 1995 and 1994 are as follows:
1996 1995 1994
---- ---- ----
(In Thousands)
Service cost $131 $ 83 $103
Interest cost on APBO 418 421 407
---- ---- ----
Postretirement benefit cost $549 $504 $510
---- ---- ----
---- ---- ----
For 1996, a 1% increase in health care cost trends would have increased the
APBO by $723,000 and the service and interest cost by $84,000.
(11) RELATED PARTY TRANSACTIONS:
- --------------------------------------------------------------------------------
Prior to 1995, the Company used a real estate complex (the Complex) owned
directly or indirectly by certain stockholders and members of the Board of
Directors for Company-sponsored seminars, the accommodation of business
guests, the housing of personnel attending corporate meetings and for other
general business purposes. In 1994, in connection with the Company's
termination of usage, the company paid $662,000 on account of the business
use of such property, and an additional $300,000 as a partial reimbursement
of deferred maintenance costs.
John F. Dorn resigned as an executive officer and director of the Company in
1993. The Company agreed to pay Mr. Dorn his salary at the time of his
resignation through September 30, 1996. In addition, the Company provided
certain other benefits and services to Mr. Dorn. The present value of the
severance package was estimated at $500,000, which amount was recorded as an
expense and a liability at December 31, 1993. In March 1994, the Company
sold certain non-strategic oil and gas properties to an entity controlled by
Mr. Dorn and another former executive officer of the Company for net
proceeds, after costs of sale and purchase price adjustments, of $3,661,000.
The Company established the sales price based upon an opinion from an
independent third party.
(12) COMMITMENTS AND CONTINGENCIES:
- --------------------------------------------------------------------------------
Future rental payments for office facilities and equipment under the
remaining terms of noncancelable leases are $1,810,000, $1,810,000,
$1,773,000, $1,615,000 and $1,090,000 for the years ending December 31, 1997
through 2001, respectively.
Net rental payments applicable to exploration and development activities and
capitalized in the oil and gas property accounts aggregated $1,050,000 in
1996, $972,000 in 1995 and $851,000 in 1994. Net rental payments charged to
expense amounted to $3,336,000 in 1996, $3,529,000 in 1995 and $3,512,000 in
1994. Rental payments include the short-term lease of vehicles. None of the
leases 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, 1996 the ProMark Netback
Pool had entered into fixed price contracts to sell approximately 10.7 BCF of
natural gas in 1997 at an average price of $1.66 per MCF and approximately
5.4 BCF of natural gas in 1998 at an average price of approximately $1.88 per
MCF. Canadian Forest is obligated to deliver approximately 25% of the volumes
of natural gas subject to these contracts.
As part of ProMark's gas marketing activities, ProMark has entered into fixed
price contracts to purchase and to resell natural gas through 1998. ProMark
has commitments to purchase and commitments to resell approximately 300,000
MCF per day through October 31, 1997 and approximately 35,000 MCF per day
thereafter through October 31, 1998. 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.
61
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(12) COMMITMENTS AND CONTINGENCIES (CONTINUED):
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.
(13) FINANCIAL INSTRUMENTS:
ENERGY SWAPS AND COLLARS: In order to hedge against the effects on the
Company's future oil and gas production of declines in oil and natural gas
prices, 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, 1996, 1995 and 1994, the
Company's gains (losses) under its swap agreements were $(10,422,000),
$3,536,000 and $1,810,000, 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.
The following table indicates outstanding energy swaps at December 31, 1996:
Product Volume Fixed Price Duration
--------------- ------------------------ ----------------- ------------
Natural Gas 441 TO 5,761 MMBTU/day $2.300 to $2.535 1/97 - 12/99
Natural Gas 100 TO 250 MMBTU/day $2.2505 to $3.003 1/97 - 12/02
Natural Gas 5,000 MMBTU/day $1.9225 1/97 - 12/97
Natural Gas 3,000 MMBTU/day $2.42 1/97 - 12/97
Natural Gas 10,000 MMBTU/day $2.728 1/97 - 2/97
Natural Gas (1) 1,200 to 1,500 MMBTU/day $1.159 (2) 1/97 -6/98
Oil 250 BBLS/day $18.85 1/97 - 12/97
Oil 332 BBLS/day $17.90 1/97 - 6/97
Oil 250 BBLS/day $20.05 1/97 - 12/97
Oil 250 BBLS/day $21.05 1/97 - 12/97
Oil (1) 350 BBLS/day $18.65 1/97 - 12/97
Oil (1) 350 BBLS/day $20.05 1/97 - 12/97
Oil (1) 350 BBLS/day $21.04 1/97 - 12/97
(1) Energy swaps related to the oil and gas operations of Canadian Forest and
Saxon.
(2) Based on Alberta Energy Company "C" (AECO "C", U.S. $) basis. All other
swaps are settled on the basis of New York Mercantile Exchange (NYMEX)
prices.
Subsequent to December 31, 1996 the Company entered into two additional oil
swaps. The first oil swap hedges 200 barrels of oil per day from February
1997 to July 1997 at a fixed price of $23.67 per barrel (NYMEX basis). The
second oil swap hedges 247 barrels of oil per day from January 1998 to
December 1998 at a fixed price of $20.00 per barrel (NYMEX basis).
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, 1996 there are six basis swaps in place through
April 1998, for a weighted average volume of 22,000 MMBTU/day. Subsequent to
December 31, 1996 the Company entered into six additional basis swaps through
December 1997, for a weighted average volume of 18,000 MMBTU/day.
62
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(13) FINANCIAL INSTRUMENTS (CONTINUED):
At December 31, 1996 the Company has an outstanding collar to hedge 10,000
MMBTU of natural gas per day from January 1997 through December 1997. The
floor and ceiling price of the collar are $2.00 and $2.37 per MMBTU (NYMEX
basis), respectively. Subsequent to December 31, 1996 the Company entered
into a collar to hedge 7,000 MMBTU of gas per day from April 1997 to September
1997. The floor and ceiling price of the collar are $2.10 and $2.50 per MMBTU
(NYMEX basis), respectively.
At December 31, 1996 the Company has an outstanding call which covers 10,000
MMBTU of natural gas per day from Janary 1997 to December 1997. In this
arrangement, the Company has effectively set a ceiling price of $2.00 per
MMBTU (NYMEX basis) in exchange for a premium of $.086 per MMBTU.
The Company is exposed to off-balance-sheet risks associated with swap or collar
agreements arising from movements in the prices of oil and natural gas and from
the unlikely event of non-performance by the counterparty to the swap or collar
agreements.
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, 1996:
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 $11,188,000 by discounting the projected future cash payments
required under the agreement by 9.7%.
SENIOR SUBORDINATED NOTES:
The fair value of the Company's 11 1/4% Senior Subordinated Notes was
approximately $107,500,000, 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 $1,751,000, of which approximately $1,168,000 has been recorded as
a liability at December 31, 1996.
ENERGY SWAP AGREEMENTS:
The fair value of the Company's energy swap agreements was a loss of
approximately $5,615,000, based upon the estimated net amount the Company would
have to pay to terminate the agreements.
BASIS SWAP AGREEMENTS:
The fair value of the Company's basis swap agreements was a gain of
approximately $173,000, based upon the estimated net amount the Company would
receive to terminate the agreements.
ENERGY COLLAR AGREEMENTS:
The fair value of the Company's energy collar agreements was a loss of
approximately $109,000, based upon the estimated net amount the Company would
have to pay to terminate the agreements.
63
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(14) MAJOR CUSTOMERS:
The Company's sales to individual customers which exceeded 10% of the Company's
total revenue in 1995 and 1994 (exclusive of the effects of energy swaps and
hedges) are shown below. No single customer accounted for more than 10% of
total revenue in 1996.
1995 1994
------- ------
(In Thousands)
Enron Affiliates $30,916 58,805
Chevron USA Production Company 11,893 12,829
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
$6,272,000, $17,217,000 and $29,046,000 represent sales recorded for deliveries
under volumetric production payments in the years ended December 31, 1996, 1995
and 1994, respectively.
(15) 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. This amount was recorded as natural
gas sales when the gas was delivered in 1991. The Company also had an unsecured
claim relating to the rejection of the gas purchase contracts.
The Company established a reserve of approximately $750,000 against the secured
portion of the bankruptcy claim in 1991. This reserve was reversed in 1994 when
it became apparent that the amount the Company would receive in the Columbia
settlement would exceed the amount of the secured claim. The reversal of the
reserve was recorded as miscellaneous revenue in 1994.
In 1995, the creditors reached agreement with Columbia regarding settlement of
the various claims. The Company recorded approximately $4,263,000 of revenue as
a result of the settlement. This amount represents the Company's portion of the
settlement amount related to its unsecured claim, net of a provision for
royalties payable.
64
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(16) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED):
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------
(In Thousands Except Per Share Amounts)
1996
- ----
REVENUE $60,870 79,544 83,969 93,091
------- ------ ------ ------
------- ------ ------ ------
EARNINGS FROM OPERATIONS $20,010 18,743 23,058 29,748
------- ------ ------ ------
------- ------ ------ ------
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
------- ------ ------ ------
------- ------ ------ ------
PRIMARY AND FULLY DILUTED LOSS PER SHARE BEFORE
EXTRAORDINARY ITEM $ (.04) (.14) .01 .10
------- ------ ------ ------
------- ------ ------ ------
PRIMARY AND FULLY DILUTED LOSS PER SHARE $ (.04) (.14) .01 .17
------- ------ ------ ------
------- ------ ------ ------
1995
- ----
Revenue $22,361 20,550 17,617 21,928
------- ------ ------ ------
------- ------ ------ ------
Earnings from operations $14,900 12,740 10,177 12,914
------- ------ ------ ------
------- ------ ------ ------
Net loss $(3,144) (4,815) (6,574) (3,463)
------- ------ ------ ------
------- ------ ------ ------
Net loss attributable to common stock $(3,684) (5,355) (7,114) (4,003)
------- ------ ------ ------
------- ------ ------ ------
Primary and fully diluted loss per share $ (.65) (.94) (.84) (.42)
------- ------ ------ ------
------- ------ ------ ------
65
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(17) 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)
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 and 1994, the Company's only business segment was oil and gas
operations, which were conducted entirely in the United States.
66
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(18) 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," (SFAS 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, 1996, 1995 and 1994:
UNITED
STATES CANADA TOTAL
------- ------ -----
(In Thousands)
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
-------- ------- -------
-------- ------- -------
1994
- ----
Property acquisition costs (undeveloped
leases and proved properties) $ 9,762 - 9,762
Exploration costs 15,693 - 15,693
Development costs 17,089 - 17,089
-------- ------- -------
Total $ 42,544 - 42,544
-------- ------- -------
-------- ------- -------
(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:
1996 1995 1994
---- ---- ----
(In Thousands)
Costs related to proved properties $ 1,381,289 1,169,636 1,109,158
Costs related to unproved properties:
Costs subject to depletion 32,007 18,011 32,288
Costs not subject to depletion 43,916 28,380 30,441
----------- --------- ---------
1,457,212 1,216,027 1,171,887
Less accumulated depletion and valuation allowance 1,001,604 941,482 895,335
----------- --------- ---------
$ 455,608 274,545 276,552
----------- --------- ---------
----------- --------- ---------
67
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(18) 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, 1996, 1995 and 1994
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)
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
--------- ------ -------
--------- ------ -------
1994
- ----
Oil and gas sales $ 114,541 - 114,541
Production expense 22,384 - 22,384
Depletion expense 64,883 - 64,883
Provision for impairment of oil and gas properties 58,000 - 58,000
--------- ------ -------
145,267 - 145,267
--------- ------ -------
Results of operations from producing activities $ (30,726) - (30,726)
--------- ------ -------
--------- ------ -------
(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 1994, 1995 and 1996 follows. The Canadian reserves at December 31,
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 13), but not on escalations based on future
conditions.
68
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(18) 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 each of the years presented, those quantities attributable to future
deliveries required under volumetric production payments (see Note 6). In
order to calculate such amounts, the Company has assumed that deliveries under
volumetric production payments are made as scheduled at expected BTU factors,
and that delivery commitments are satisfied through delivery of actual volumes
as opposed to cash settlements.
The Company has also presented, 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 each of the years presented. This additional information is not presented
in accordance with SFAS No. 69; however, the Company believes this additional
information is useful in assessing its reserve acquisitions and financial
position on a comprehensive basis.
69
FORREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(18) 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, 1993 7,797 - 7,797 244,096 - 244,096
Revisions of previous estimates 989 - 989 7,848 - 7,848
Extensions and discoveries 41 - 41 9,894 - 9,894
Production (1,361) - (1,361) (32,043) - (32,043)
Sales of reserves in place (170) - (170) (6,377) - (6,377)
Purchases of reserves in place 17 - 17 8,220 - 8,220
----- ------ ------ ------- ------- -------
Balance at December 31, 1994 7,313 - 7,313 231,638 - 231,638
Additional disclosures:
Volumes attributable to volumetric
production payments 219 - 219 15,358 - 15,358
----- ------ ------ ------- ------- -------
Balance at December 31, 1994, including
volumes attributable to volumetric
production payments 7,532 - 7,532 246,996 - 246,996
----- ------ ------ ------- ------- -------
----- ------ ------ ------- ------- -------
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
ADDITIONAL DISCLOSURES:
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
----- ------ ------ ------- ------- -------
----- ------ ------ ------- ------- -------
70
FORREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) (CONTINUED):
Purchases of reserves in place represent volumes recorded on the closing dates
of the acquisitions for financial accounting purposes. The revisions of
previous estimates for natural gas in 1994 include 5,833 MMCF for an adjustment
related to the change in accounting for oil and gas sales from the sales method
to the entitlements method.
OIL AND CONDENSATE GAS
------------------------- -------------------------------
(MBBLS) (MMCF)
UNITED UNITED
STATES CANADA TOTAL STATES CANADA TOTAL
------ ------ ----- ------ ------ -----
Proved developed reserves at:
December 31, 1993 6,377 - 6,377 187,534 - 187,534
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
The Company's proved developed reserves, including amounts attributable to
volumetric production payments, are shown below. This disclosure is presented
as additional information and is not intended to represent required disclosure
pursuant to SFAS No. 69.
OIL AND CONDENSATE GAS
------------------------- -------------------------------
(MBBLS) (MMCF)
UNITED UNITED
STATES CANADA TOTAL STATES CANADA TOTAL
------ ------ ----- ------ ------ -----
Proved developed reserves, including
amounts attributable to volumetric
production payments at:
December 31, 1993 6,778 - 6,778 216,820 - 216,820
December 31, 1994 6,994 - 6,994 194,932 - 194,932
December 31, 1995 5,752 3,188 8,940 162,709 14,184 176,893
DECEMBER 31, 1996 5,311 13,260 18,571 168,699 70,856 239,555
(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, 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 13.
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 expenses
have not been considered.
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 each of the years presented,
amounts attributable to future deliveries required under volumetric production
payments. In order to calculate such amounts, the Company has assumed that
deliveries under
71
FORREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) (CONTINUED):
- -------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
volumetric production payments are made as scheduled, that production costs
corresponding to the volumes delivered are incurred by the Company at average
rates for the properties subject to the production payments, and that delivery
commitments are satisfied through delivery of actual volumes as opposed to cash
settlements.
The Company has also presented, 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 are shown on the Company's balance sheets for each of the years
presented. This additional information is not required to be presented in
accordance with SFAS 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, 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.
72
FORREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(18) 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)
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.
73
FORREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING
ACTIVITIES (UNAUDITED) (CONTINUED):
- -----------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
DECEMBER 31, 1994
-----------------------------------
UNITED
STATES CANADA TOTAL
------ ------ -----
(In Thousands)
Future oil and gas sales $ 502,186 - 502,186
Future production and development costs (193,376) - (193,376)
--------- -------- ---------
Future net revenue 308,810 - 308,810
10% annual discount for estimated timing of cash flows (100,480) - (100,480)
--------- -------- ---------
Present value of future net cash flows before income taxes 208,330 - 208,330
Present value of future income tax expense (781) - (781)
--------- -------- ---------
Standardized measure of discounted future net cash flows 207,549 - 207,549
Additional disclosures:
Amounts attributable to volumetric production payments 22,600 - 22,600
--------- -------- ---------
Total discounted future net cash flows, including amounts
attributable to volumetric production payments $ 230,149 - 230,149
--------- -------- ---------
--------- -------- ---------
Undiscounted future income tax expense was $1,348,000 at December 31, 1994.
74
FORREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(18) 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
is as follows. At December 31, 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, 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. During March 1997, the Company was receiving an average
natural gas price of approximately $1.90 per MCF in the U.S. and
approximately $1.70 per MCF in Canada and was receiving average liquids
prices of approximately $19.20 per barrel in the U.S. and approximately
$17.00 per barrel in Canada. Had the lower March 1997 prices been used, the
Company's standardized measure of discounted future net cash flows relating
to proved oil and gas reserves at December 31, 1996 would have been
significantly reduced.
75
FORREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(18) 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
-------- ------- --------
-------- ------- --------
76
FORREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
(18) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) (CONTINUED):
- -----------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
DECEMBER 31,
1994
--------------
(In Thousands)
Standardized measure of discounted future net cash
flows relating to proved oil and gas reserves, at
beginning of year $262,176
Changes resulting from:
Sales of oil and gas, net of production costs (69,607)
Net changes in prices and future production costs (80,526)
Net changes in future development costs 7,432
Extensions, discoveries and improved recovery 10,817
Previously estimated development costs incurred during
the period 10,000
Revisions of previous quantity estimates 16,840
Sales of reserves in place (10,630)
Purchases of reserves in place 8,467
Accretion of discount on reserves at beginning of
year before income taxes 32,334
Net change in income taxes 20,246
--------
Standardized measure of discounted future net cash
flows relating to proved oil and gas reserves, at
end of year 207,549
Additional disclosures:
Amounts attributable to volumetric production payments 22,600
--------
Total discounted future net cash flows relating to
proved oil and gas reserves, including amounts
attributable to volumetric production payments,
at end of year $230,149
--------
--------
77
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 on May 14, 1997 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, 1996 and 1995
3. Consolidated Statements of Operations - Years ended
December 31, 1996, 1995 and 1994
4. Consolidated Statements of Shareholders' Equity - Years
ended December 31, 1996, 1995 and 1994
5. Consolidated Statements of Cash Flows - Years ended
December 31, 1996, 1995 and 1994
6. Notes to Consolidated Financial Statements - Years
ended December 31, 1996, 1995 and 1994
(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).
78
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 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).
*Exhibit 4.4 Second Amended and Restated Credit Agreement dated as of
January 31, 1997 between Forest Oil Corporation and Subsidiary Guarantors and
The Chase Manhattan Bank, as agent.
Exhibit 4.5 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 4.6 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
79
(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 4.7 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 4.8 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.
*Exhibit 4.9 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.
Exhibit 4.10 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 4.11 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 4.12 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).
Exhibit 4.13 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 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 10.2 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 10.3 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 10.4 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 10.5 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 10.6 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).
80
Exhibit 10.7 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 10.8 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 10.9 Tranche A Warrant to Purchase 3,888,888 shares of Common
Stock issued to The Anschutz Corporation dated July 27, 1995 incorporated
herein by reference to Exhibit 99.6 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 11 Computation of Earnings Per Share of Common Stock. Forest
Oil Corporation and Subsidiaries.
*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, Richard
J. Callahan, Cortlandt S. Dietler, William L. Dorn, Jordan L. Haines, David
H. Keyte, James H. Lee, Craig D. Slater, Joan C. Sonnen, Drake S. Tempest,
Michael B. Yanney.
*Exhibit 27 Financial Data Schedule
- --------------------
* filed herewith.
(b) Reports on Form 8-K
The following reports on Form 8-K were filed by Forest during the last
quarter of 1996:
Date of Report Item Reported Financial Statements Filed
-------------- ------------- --------------------------
October 30, 1996 Item 5 None
November 15, 1996 Item 5 None
81
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 27, 1997 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 March 27, 1997
(Robert S. Boswell) Officer (Principal Executive
Officer)
David H. Keyte* Vice President and Chief March 27, 1997
(David H. Keyte) Financial Officer (Principal
Financial Officer)
Joan C. Sonnen* Controller March 27, 1997
(Joan C. Sonnen) (Chief Accounting Officer)
Philip F. Anschutz* Directors of the Registrant March 27, 1997
(Philip F. Anschutz)
Robert S. Boswell*
(Robert S. Boswell)
William L. Britton*
(William L. Britton)
Richard J. Callahan*
(Richard J. Callahan)
Cortland S. Dietler*
(Cortland S. Dietler)
William L. Dorn*
(William L. Dorn)
Jordan L. Haines*
(Jordan L. Haines)
James H. Lee*
(James H. Lee)
Craig D. Slater*
(Craig D. Slater)
Drake S. Tempest*
(Drake S. Tempest)
Michael B. Yanney*
(Michael B. Yanney)
*By /s/ Daniel L. McNamara March 27, 1997
--------------------------------
Daniel L. McNamara
(as attorney-in-fact for
each of the persons indicated)
82