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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
(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, 1995
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
Warrants to purchase shares of Common Stock
$.75 Convertible Preferred Stock, Par Value $.01 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 persons other than
non-affiliates of the registrant was approximately $231,371,978 as of February
29, 1996 (based on the last sale price of such stock as quoted on the NASDAQ
National Market).
There were 24,527,575 shares of the registrant's Common Stock, Par Value
$.10 Per Share outstanding as of February 29, 1996.
Document incorporated by reference: Proxy Statement of Forest Oil
Corporation relative to the Annual Meeting of Shareholders to be held on May 8,
1996, which is incorporated into Part III of this Form 10-K.
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TABLE OF CONTENTS
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Page No.
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PART I
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Item 1. Business 1
Item 2. Properties 10
Item 3. Legal Proceedings 16
Item 4. Submission of Matters to a Vote of Security Holders 17
Item 4A. Executive Officers of Forest 17
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 19
Item 6. Selected Financial and Operating Data 22
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations 24
Item 8. Financial Statements and Supplementary Data 33
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure 33
PART III
Item 10. Directors and Executive Officers of the Registrant 69
Item 11. Executive Compensation 69
Item 12. Security Ownership of Certain Beneficial Owners and Management 69
Item 13. Certain Relationships and Related Transactions 69
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 69
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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, following
two recent acquisitions, in Canada. Forest's principal reserves and producing
properties are located in the Gulf of Mexico, Texas, Oklahoma and Canada. The
Company currently operates 43 offshore platforms in the Gulf and Mexico, and
1995 production from this area accounted for approximately 78% of the Company's
reported historical 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 and
Denver, Colorado. In January 1996 the Company established an administrative and
production office in Calgary, Alberta, Canada. Forest's corporate headquarters
are located in Denver, Colorado. On December 31, 1995, Forest had 173
employees, of whom 115 were salaried and 58 were hourly. On March 20, 1996,
Forest had 177 employees in the United States, of whom 119 were salaried and 58
were hourly, Canadian Forest had 51 salaried employees and ProMark had 16
salaried employees.
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. In recent years, the Company has grown primarily by acquiring
reserves with exploitation potential, increasing production from existing fields
and participating in exploration through farmout arrangements. The Company
seeks to acquire interests in properties in which it would have a significant
working interest and which it can operate. From January 1, 1991 through
December 31, 1995 the Company acquired approximately 281 BCFE of estimated
proved reserves, located primarily in the Gulf of Mexico, Texas and western
Canada.
During 1995, the Company's acquisitions totaled 44.0 BCFE at an average property
acquisition cost of $.61 per MCFE. These amounts represent primarily the
reserves of Saxon Petroleum Inc. (Saxon), a consolidated subsidiary of the
Company in which the Company purchased a 56% economic interest on December 20,
1995. Saxon is an Alberta, Canada corporation engaged in oil and gas
exploration and production primarily in western Canada.
On January 31, 1996 Forest acquired ATCOR Resources Ltd. for approximately
$134,900,000, exclusive of acquisition costs of approximately $1,800,000. 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 154 BCFE at an average property
acquisition cost of $.66 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
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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.
On a pro forma basis, the Company had estimated proved reserves of 455 BCFE at
December 31, 1995 of which approximately 73% were natural gas reserves. This
represents an increase of 56% compared to estimated proved reserves of 292 BCFE
at December 31, 1994, of which approximately 85% was natural gas.
Throughout the remainder of 1996, the Company 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.
The Company participates in exploration activities through selective drilling
for its own account, as well as through farmout arrangements. Farmouts enable
Forest to participate in its exploration prospects without incurring additional
exploration costs, although with a reduced ownership in each prospect. For
further information concerning the Company's farmout activity, see Item 2.
Properties.
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 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.
In recent years, the Company has not been 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 1996, the Company intends to pursue
its acquisition and exploitation strategy while continuing its efforts to
improve its balance sheet and liquidity. The Company has also significantly
increased the amount of capital expenditures it has budgeted for exploration
activities. 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.
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. For the month of March 1996, approximately 19% of the Company's U.S.
natural gas was committed to both interstate and intrastate natural gas pipeline
companies, primarily under volumetric production payment
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agreements and long-term contracts. The remainder 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.
In Canada, Canadian Forest's 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. The Netback Pool
gas sales in 1995 averaged 118 MMCF per day, of which Canadian Forest supplied
approximately 40 MMCF per day or approximately 80% of its current natural gas
production.
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, commodity futures
contracts, swaps or similar hedging instruments, 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 third party agreements will
fail to perform their contractual obligations.
For much of the past decade, the markets for oil and natural gas have been
volatile. The Company anticipates that such markets will continue to be
volatile over the next year. Price fluctuations in the natural gas spot market
have a significant impact on the Company's business because most of the
Company's reserves are attributable to natural gas, most of its current
production consists of natural gas and a large portion of its natural gas
production is sold in the spot market. At December 31, 1995, approximately 86%
of Forest's estimated proved reserves in the U.S., including volumes
attributable to volumetric production payments, consisted of natural gas on an
MCFE basis. During 1995, 83% of the Company's total U.S. production on the same
basis consisted of natural gas. Approximately 72% of such 1995 natural gas
production was sold in the spot market. On a pro forma basis at December 31,
1995, approximately 55% of Forest's estimated proved reserves in Canada
consisted of natural gas on an MCFE basis. During 1995, 63% of Forest's pro
forma Canadian production consisted of natural gas.
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 exposure to anticipated fluctuations in future oil and
natural gas prices. The volumetric production payments that the Company has
entered into further minimize the price volatility to which the Company is
subject. For further information concerning market conditions, 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 and 13
of Notes to Consolidated Financial Statements.
Demand for natural gas is highly seasonal, with demand generally higher in the
colder winter months and in hot summer months. As a result, the price received
for spot market natural gas may vary significantly between seasonal periods. 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.
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, the majority of Canadian Forest's natural gas
production is sold under the ProMark Netback Pool to long-term buyers. The loss
of one or more of such long-term buyers could have an adverse effect on Canadian
Forest and ProMark. Substantially all of Forest's oil 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.
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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, distributers
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, although there is no current shortage of such
equipment. 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, and 636-B
(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
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subject the Company to more restrictive pipeline imbalance tolerances and
greater penalties for violation of those tolerances. Numerous parties have
filed petitions for review of Order No. 636, as well as orders in individual
pipeline restructuring proceedings. Upon such judicial review, these orders
may be remanded or reversed in whole or in part. With Order No. 636 subject
to court review, it is difficult to predict with precision its ultimate
effects.
The FERC has announced its intention to re-examine certain of its
transportation-related policies, including the appropriate manner in which
interstate pipelines release transportation capacity under Order No. 636, and
the use of market-based rates for interstate gas transmission. While any
resulting FERC action would affect the Company only indirectly, the FERC's
current rules and policy statement may have the effect of enhancing competition
in natural gas markets by, among other things, encouraging non-producer natural
gas marketers to engage in certain purchase and sale transactions. The Company
cannot predict what action the FERC will take on these matters, nor can it
accurately predict whether the FERC's actions will achieve the goal of
increasing competition in markets in which the Company's natural gas is sold.
However, the Company does not believe that it will be treated materially
differently than other natural gas producers and marketers with which it
competes.
Recently, the FERC issued a policy statement on how interstate natural gas
pipelines can recover the costs of new pipeline facilities. While this policy
statement affects the Company only indirectly, in its present form, the new
policy should enhance competition in natural gas markets and facilitate
construction of gas supply laterals. However, requests for rehearing of this
policy statement are currently pending. The Company cannot predict what action
the FERC will take on these requests.
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 FERC's decision in this matter
is currently the subject of various petitions for judicial review. 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
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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.
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 recently 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.
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
In August 1993, the MMS published an advance notice of its intention to adopt a
rule under the Oil Pollution Act of 1990 (OPA 90) that would require owners and
operations of oil and gas facilities located on or adjacent to waters of the
United States to establish $150,000,000 in financial responsibility to cover oil
spill related liabilities. Compliance with the proposed rule could be
financially burdensome for many small oil and gas companies, and in June 1995,
the U.S. House of Representatives approved a bill that would amend OPA 90 to
reduce the level of financial responsibility to $35,000,000. The Clinton
Administration has expressed its support for the pending legislation, but the
U.S. Senate has not yet taken any action on the bill approved by the House of
Representatives. The Company cannot predict whether Congress will reduce the
level of financial responsibility required under OPA 90 nor can it predict the
final form of any financial responsibility rule that might be adopted, but any
such action has the potential to result in the imposition of substantial
additional annual costs on the Company or otherwise materially adversely affect
the Company. The impact of the rule should not be any more adverse to the
Company than it will be to other similarly situated or less capitalized owners
or operators in the Gulf of Mexico and other affected regions. The MMS has
indicated that it will not move forward with the adoption of the rule until the
United States Congress has had an opportunity to act on the pending amendments
to OPA 90.
REGULATION - CANADA
The oil and natural gas industry in Canada is subject to extensive controls and
regulations imposed by various levels of government. It is not expected that
any of these controls or regulations will affect the operations of the Company
in a manner materially different than they would affect other oil and gas
companies of similar size.
In Canada, producers of oil negotiate sales contracts directly with oil
purchasers, with the result that the market determines the price of oil. The
price depends in part on oil quality, prices of competing fuels, distance to
market and the value of refined products. Oil exports may be made pursuant to
export contracts with terms not exceeding one year in the case of light crude,
and not exceeding two years in the case of heavy crude, provided that an order
approving any such export has been obtained from the National Energy Board
(NEB). Any oil export to be made
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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 not eligible for any ARTC
credits on its existing properties.
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.
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OPERATING HAZARDS AND ENVIRONMENTAL MATTERS
The oil and gas business involves a variety of operating risks, including the
risk of fire, explosions, blow-outs, pipe failure, casing collapse, abnormally
pressured formations and environmental hazards such as oil spills, gas leaks,
ruptures and discharges of toxic gases, the occurrence of any of which could
result in substantial losses to the Company due to injury or loss of life,
severe damage to or destruction of property, natural resources and equipment,
pollution or other environmental damage, clean-up responsibilities, regulatory
investigation and penalties and suspension of operations. In addition, the
Company currently operates offshore and is subject to the additional hazards of
marine operations, such as capsizing, collision and adverse weather and sea
conditions. Such hazards may hinder or delay drilling, development and on-line
production operations.
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. 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.
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 Company maintains pollution insurance against
the costs of clean-up operations, public liability and physical
8
<PAGE>
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.
OTHER FOREIGN OPERATIONS
In 1992, the Company sold substantially all of its former Canadian operations to
CanEagle Resources Corporation (CanEagle). In June 1994, CanEagle sold a
significant portion of its oil and gas properties in Canada to a third party. In
conjunction with this transaction, the Company exchanged its investment in
CanEagle for shares of preferred stock of a newly formed entity, Archean Energy,
Ltd. (Archean). In connection with the Saxon transaction, the Company
transferred its Archean preferred stock to Saxon.
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.
9
<PAGE>
ITEM 2. PROPERTIES
Forest's principal reserves and producing properties are oil and gas properties
located in the Gulf of Mexico, Texas, Oklahoma and western 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 16 of Notes to Consolidated Financial
Statements.
Since January 1, 1995, 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 to Forest's Gulf of Mexico reserves
and 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 on a historical basis for the years ended December 31, 1995,
1994 and 1993 and on a pro forma basis including Saxon and Canadian Forest for
the year ended 1995:
Net Natural Gas and Liquids Production (1)(2)
---------------------------------------------
Pro forma
1995 1995 (3) 1994 (4) 1993
---------- -------- -------- ------
United States:
Natural Gas (MMCF) 33,342 33,342 48,048 41,114
Liquids (MBBLS) 1,173 1,173 1,543 1,493
Canada:
Natural Gas (MMCF) 18,428 - - -
Liquids (MBBLS) 1,828 - - -
(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 are not significant.
(4) 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.
10
<PAGE>
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 in the United States on a historical basis for the years ended
December 31, 1995, 1994 and 1993 for Forest and its subsidiaries and on a pro
forma basis including Saxon and Canadian Forest for the year ended 1995:
<TABLE>
Canada
--------- United States
Pro forma -------------------------
1995 1995 1994 1993
--------- ------- ------ ------
<S> <C> <C> <C> <C>
Average Sales Prices:
Natural Gas
Production under long-term fixed
price contracts (MMCF) (1) (4) 9,414 16,656 19,065
Average contract sales price (per MCF) $ 1.75 1.78 1.65
Production sold on the spot market (MMCF) (4) 23,928 31,392 22,049
Spot sales price received (per MCF) (2) $ 1.66 1.90 2.21
Effects of energy swaps (per MCF) (3) .17 .06 (.13)
------- ------ ------
Average spot sales price (per MCF) (2) $ 1.83 1.96 2.08
Total natural gas production (MMCF) 18,428 33,342 48,048 41,114
Average sales price (per MCF) (2) $ 1.16 1.77 1.90 1.88
Liquids:
Oil and Condensate
Total production (MBBLS) 1,450 1,121 1,482 1,464
Sales price received (per BBL) $15.44 16.36 14.97 16.25
Effects of energy swaps (per BBL) (3) - (.50) (.14) .58
------ ------- ------ ------
Average sales price (per BBL) $15.44 15.86 14.83 16.83
Natural Gas Liquids
Total production (MBBLS) 378 52 61 29
Average sales price (per BBL) $ 8.76 15.81 14.79 24.02
Total liquids production (MBBLS) 1,828 1,173 1,543 1,493
Average sales price (per BBL) $14.05 15.86 14.83 16.97
Average production cost (per MCFE) (5) $ .51 .56 .39 .39
</TABLE>
- ---------------
(1) Production under long-term fixed price contracts includes scheduled
deliveries under volumetric production payments, net of royalties. For
further information concerning volumes and prices recorded under volumetric
production payments, see Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations and Note 6 of Notes to
Consolidated Financial Statements.
(2) Amounts shown for 1995 exclude the effects of a gas contract settlement.
Including such amount, the spot sales price received, average spot sales
price and average sales price for natural gas in 1995 were $1.79, $1.96 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 fluctuation. Hedged natural gas volumes were 10,146 MMCF,
12,184 MMCF and 8,057 MMCF for the years ended December 31, 1995, 1994 and
1993, respectively. Hedged oil and condensate volumes were 498,000 BBLS,
370,000 BBLS and 720,000 BBLS for the years ended December 31, 1995, 1994
and 1993, respectively.
(4) Pro forma data concerning volumes sold under long-term fixed price contracts
versus volumes sold on the spot market is not available.
(5) Production costs were converted to common units of measure using a
conversion ratio of one barrel of oil to six MCF of natural gas and one
long ton of sulfur to 15 MCF of natural gas. Such production costs exclude
all depreciation, depletion and provision for impairment associated with
property and equipment.
11
<PAGE>
PRODUCTIVE WELLS
The following summarizes total gross and net productive wells of the Company and
its subsidiaries on a historical basis, including the wells owned by Saxon, at
December 31, 1995 and on a pro forma basis including Canadian Forest for the
year ended December 31, 1995:
PRODUCTIVE WELLS (1)
------------------------
UNITED STATES CANADA
------------- ------
Historical
----------
Gross (2)
Gas 290 99
Oil 170 510
----- -----
Totals (3) 460 609
----- -----
----- -----
Net (4)
Gas 93.3 16.4
Oil 116.3 95.8
----- -----
Totals 209.6 112.2
----- -----
----- -----
Pro forma
---------
Gross (2)
Gas 290 383
Oil 170 1,036
----- -----
Totals (3) 460 1,419
----- -----
----- -----
Net (4)
Gas 93.3 109.6
Oil 116.3 208.4
----- -----
Totals 209.6 318.0
----- -----
----- -----
(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 32 dual completions in the United States on a historical and pro
forma basis and 3 dual completions on a pro forma basis 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.
DEVELOPED AND UNDEVELOPED ACREAGE
Forest and its subsidiaries held acreage on a historical basis, including the
acreage held by Saxon, as set forth below at December 31, 1995 and 1994 and
on a pro forma basis including Canadian Forest at December 31, 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.
12
<PAGE>
Developed Undeveloped
Acreage (1) Acreage (2)
------------------ -------------------
Gross (3) Net (4) Gross (3) Net (4)
--------- ------- --------- -------
United States:
Louisiana Offshore 138,636 62,265 63,245 28,306
Oklahoma 63,015 21,661 8,142 1,456
Texas Onshore 122,117 47,452 14,473 9,844
Texas Offshore 39,622 29,483 11,520 8,640
Wyoming 8,477 4,484 54,204 24,367
Other 25,553 10,999 3,610 1,577
------- ------- --------- -------
397,420 176,344 155,194 74,190
Canada 99,060 35,271 17,160 8,816
------- ------- --------- -------
Total acreage at December 31, 1995 496,480 211,615 172,354 83,006
------- ------- --------- -------
------- ------- --------- -------
Total acreage at December 31, 1994 465,045 204,071 219,730 155,563
------- ------- --------- -------
------- ------- --------- -------
Pro forma acreage at December 31, 1995 802,521 313,308 1,008,475 316,989
------- ------- --------- -------
------- ------- --------- -------
(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 1995, the Company's gross and net developed acreage increased
approximately 7% and 4%, respectively, primarily as a result of the Saxon
acquisition, offset in part by the sale of developed acreage as well as lease
expirations. The Company's gross and net undeveloped acreage decreased
approximately 22% and 47%, respectively, primarily due to lease expirations,
offset partially by the acquisition of Saxon.
Approximately 26% of the Company's total net undeveloped acreage is under leases
that have terms expiring in 1996, if not held by production, and another
approximately 7% of net undeveloped acreage will expire in 1997 if not also held
by production.
13
<PAGE>
DRILLING ACTIVITY
Forest and its subsidiaries owned interests in net exploratory and net
development wells for the years ended December 31, 1995, 1994 and 1993 as set
forth below. This information does not include wells drilled under farmout
agreements, nor does it include any data with respect to wells drilled by Saxon
or Canadian Forest.
United States
--------------------
1995 1994 1993
---- ---- ----
Net Exploratory Wells: (1)
Dry (2) 1.3 2.0 1.2
Productive (3) .3 1.3 .3
--- --- ---
1.6 3.3 1.5
--- --- ---
--- --- ---
Net Development Wells: (1)
Dry (2) - - -
Productive (3) .6 2.1 3.0
--- --- ---
.6 2.1 3.0
--- --- ---
--- --- ---
(1) 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.
(2) 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.
(3) Productive wells are producing wells and wells capable of production,
including wells that are shut-in.
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 1995, two development wells and 14 exploratory wells were drilled under
farmout agreements. The two development wells were productive. Six of the
exploratory wells were productive, of which three were subsequently sold; seven
were dry holes; and one is in the process of being drilled at year-end.
PRESENT ACTIVITIES
At December 31, 1995, Forest and its subsidiaries had two exploratory wells that
were in the process of being drilled. One of these two wells was determined to
be productive in January, 1996 and the other is currently being evaluated.
14
<PAGE>
DELIVERY COMMITMENTS
At December 31, 1995 Forest and its subsidiaries were obligated to deliver, or
to make cash settlement with respect to, approximately 8.0 BCF of natural gas
and 87,000 barrels of oil under the terms of volumetric production payments.
The delivery commitments cover approximately 14% and 4% of the estimated net
proved reserves of natural gas and oil, respectively, attributable to the
subject properties. The production payments are nonrecourse to other properties
owned by the Company. The Company is further obligated to deliver approximately
.8 BCF of natural gas under existing long-term contracts. Canadian Forest
markets approximately 100 MMCF/day under medium- and long-term gas sales
contracts to a number of Canadian and United States resale markets. Canadian
Forest, on behalf of ProMark, has currently contracted with 23 Canadian
producers to purchase a quantity of gas which, when aggregated with gas produced
by Canadian Forest, constitutes the Netback Pool which is sufficient to serve
the requirements of all the resale markets. 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 17 of Notes to Consolidated Financial Statements.
15
<PAGE>
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, 1995 and on a pro forma basis for the year ended December 31, 1995
giving effect to the Saxon and Canadian Forest acquisitions. 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.
<TABLE>
Years Ended December 31,
Pro forma ------------------------------------------------
1995(1) 1995 1994(2) 1993 1992(3) 1991
--------- -------- ------- ------- ------- -------
(In Thousands Except per Share Amounts and Volumes)
<S> <C> <C> <C> <C> <C> <C>
FINANCIAL DATA
Revenue $ 269,781 82,456 115,947 105,148 113,186 69,897
--------- -------- ------- ------- ------- -------
--------- -------- ------- ------- ------- -------
Earnings (loss) before income taxes,
cumulative effects of changes in
accounting principles and
extraordinary items $ (7,768) (18,003) (67,844) (10,705) 11,286 (52,262)
--------- -------- ------- ------- ------- -------
--------- -------- ------- ------- ------- -------
Earnings (loss) before cumulative
effects of changes in accounting
principles and extraordinary items $ (14,117) (17,996) (67,853) (9,355) 7,298 (34,850)
--------- -------- ------- ------- ------- -------
--------- -------- ------- ------- ------- -------
Earnings (loss) before extraordinary items $ (14,117) (17,996) (81,843) (10,478) 7,298 (34,850)
--------- -------- ------- ------- ------- -------
--------- -------- ------- ------- ------- -------
Net earnings (loss) $ (14,117) (17,996) (81,843) (21,213) 7,298 (25,348)
--------- -------- ------- ------- ------- -------
--------- -------- ------- ------- ------- -------
Weighted average number of common
shares outstanding 22,301 7,360 5,619 4,399 2,755 2,499
--------- -------- ------- ------- ------- -------
--------- -------- ------- ------- ------- -------
Net earnings (loss) attributable to
common stock $ (16,277) (20,156) (84,004) (23,463) 4,950 (30,557)
--------- -------- ------- ------- ------- -------
--------- -------- ------- ------- ------- -------
Primary earnings (loss) per share: (4)
Earnings (loss) before cumulative effects
of changes in accounting principles
and extraordinary items $ (.73) (2.74) (12.46) (2.64) 1.80 (16.03)
--------- -------- ------- ------- ------- -------
--------- -------- ------- ------- ------- -------
Earnings (loss) before extraordinary items $ (.73) (2.74) (14.95) (2.90) 1.80 (16.03)
--------- -------- ------- ------- ------- -------
--------- -------- ------- ------- ------- -------
Net earnings (loss) attributable to
common stock $ (.73) (2.74) (14.95) (5.34) 1.80 (12.23)
--------- -------- ------- ------- ------- -------
--------- -------- ------- ------- ------- -------
Total assets $ 517,990 321,043 324,832 426,755 378,532 296,189
--------- -------- ------- ------- ------- -------
--------- -------- ------- ------- ------- -------
Long-term obligations $ 237,650 236,155 271,128 288,588 250,672 203,136
--------- -------- ------- ------- ------- -------
--------- -------- ------- ------- ------- -------
Shareholders' equity $ 180,241 44,297 6,086 88,156 59,881 54,840
--------- -------- ------- ------- ------- -------
--------- -------- ------- ------- ------- -------
</TABLE>
22
<PAGE>
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA (CONTINUED)
<TABLE>
Years Ended December 31,
Pro forma ------------------------------------------------
1995(1) 1995 1994(2) 1993 1992(3) 1991
--------- -------- ------- ------- ------- -------
(In Thousands Except per Share Amounts and Volumes)
<S> <C> <C> <C> <C> <C> <C>
OPERATING DATA
Annual production (5):
Gas (MMCF) 51,770 33,342 48,048 41,114 29,174 23,877
Liquids (MBBLS) 3,001 1,173 1,543 1,493 1,450 847
Average price received (5):
Gas (per MCF) (6) $ 1.57 1.77 1.90 1.88 1.70 1.84
Liquids (per Barrel) $ 14.76 15.86 14.83 16.97 18.14 25.31
Capital expenditures $ 77,368 52,744 42,544 170,821 106,627 35,664
Proved Reserves (5) (7):
Gas (MMCF) 330,166 238,128 246,996 273,382 194,655 193,471
Liquids (MBBLS) 20,788 10,541 7,532 8,198 7,560 5,315
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves (7) $ 333,676 256,917 207,549 262,176 190,971 166,454
Total discounted future net cash flows
relating to proved oil and gas reserves,
including amounts attributable to
volumetric production payments (7) $ 342,152 265,393 230,149 299,053 227,009 188,069
</TABLE>
- ---------------
(1) The pro forma financial and operating data as of December 31, 1995 gives
effect to the public offering of common stock and the Canadian Forest
acquisition as if they occurred on that date and the pro forma financial
and operating data for the year ended December 31, 1995 assumes the
acquisitions of Saxon and Canadian Forest occurred as of January 1, 1995.
See Notes 2 and 9 of Notes to Consolidated Financial Statement.
(2) 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.
(3) 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.
(4) 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.
(5) Includes amounts attributable to required deliveries under volumetric
production payments. See Notes 6 and 17 of Notes to Consolidated Financial
Statements.
(6) Amounts shown for 1995 and pro forma 1995 exclude the effects of a gas
contract settlement. Including such amount, the average sales prices for
1995 and pro forma 1995 were $1.90 and $1.64 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.
(7) The 1995 and pro forma 1995 amounts include 100% of the reserves owned by
Saxon, a consolidated subsidiary in which the Company holds a 56% economic
interest. See Note 2 of Notes to Consolidated Financial Statements.
23
<PAGE>
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). 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 the resolution of a gas contract settlement. The net
loss for 1994 was $81,843,000 compared to a net loss of $21,213,000 in 1993.
The 1994 loss includes 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 "Changes in
Accounting".
REVENUE. Total revenue decreased 29% to $82,456,000 in 1995 from $115,947,000
in 1994, and increased 10% in 1994 from $105,148,000 in 1993.
Oil and gas sales decreased to $82,275,000 from $114,541,000, or by
approximately 28% in 1995 compared to 1994. Oil and gas sales in 1995 includes
$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 represents
approximately 5% of total oil and gas sales in 1995.
In 1995, natural gas and oil production volumes were down 31% and 24%,
respectively, compared to 1994. These decreases result primarily from limited
capital expenditures in 1994 and 1995 that did not allow the Company to replace
existing production through acquisitions and drilling. The Company expects this
trend to reverse in 1996 as a result of the Saxon and Canadian Forest
acquisitions coupled with planned increases in its domestic capital investment
program. 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 increased to $114,541,000 from $102,883,000, or by
approximately 11%, in 1994 compared to 1993 due primarily to increased natural
gas production from properties acquired throughout 1993 and the effects of the
change in method of accounting for oil and gas sales, partially offset by normal
production declines. The change in method of accounting increased earnings from
operations (oil and gas sales less oil and gas production expenses) by
$3,584,000 in 1994. In 1994, natural gas production volumes increased 17%
compared to 1993 while oil production volumes were 3% higher. The increase in
revenue attributable to increased production was partially offset by a 13%
decrease in the average sales price for oil. The average sales price for
natural gas in 1994 did not differ significantly from the 1993 price.
Oil and gas sales to Enron and certain of its affiliates (Enron Affiliates), the
Company's largest customer, represented approximately 38% of oil and gas sales
in 1995, compared to 51% in 1994 and 61% in 1993. The decreases during this
period 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 decreased to approximately 8 BCFE in 1995 from
approximately 16 BCFE in 1994 as a result of lower production volumes available
for sale and spot market sales to buyers other than Enron affiliates. Spot
market sales to Enron Affiliates in 1993 were approximately 14 BCFE.
24
<PAGE>
The production volumes and average sales prices for the years ended December 31,
1995, 1994 and 1993 for Forest and its subsidiaries were as follows:
Years Ended December 31,
---------------------------
1995 1994 1993
------- ------ ------
NATURAL GAS
Production under long-term fixed
price contracts (MMCF) (1) 9,414 16,656 19,065
Average contract sales price (per MCF) $ 1.75 1.78 1.65
Production sold on the spot market (MMCF) 23,928 31,392 22,049
Spot sales price received (per MCF) (2) $ 1.66 1.90 2.21
Effects of energy swaps (per MCF) (3) .17 .06 (.13)
------- ------ ------
Average spot sales price (per MCF) (2) $ 1.83 1.96 2.08
Total natural gas production (MMCF) 33,342 48,048 41,114
Average sales price (per MCF) (2) $ 1.77 1.90 1.88
LIQUIDS
Oil and condensate:
Total production (MBBLS) 1,121 1,482 1,464
Sales price received (per BBL) $ 16.36 14.97 16.25
Effects of energy swaps (per BBL) (3) (.50) (.14) .58
------- ------ ------
Average sales price (per BBL) $ 15.86 14.83 16.83
Natural gas liquids:
Total production (MBBLS) 52 61 29
Average sales price (per BBL) $ 15.81 14.79 24.02
Total liquids production (MBBLS) 1,173 1,543 1,493
Average sales price (per BBL) $ 15.86 14.83 16.97
- ---------------
(1) Production under long-term fixed price contracts includes scheduled
deliveries under volumetric production payments, net of royalties. For
further information concerning volumes and prices recorded under volumetric
production payments, see Notes 6 and 17 of Notes to Consolidated Financial
Statements.
(2) Amounts shown for 1995 exclude the effects of a gas contract settlement.
Including such amount, the spot sales price received, average spot sales
price and average sales price for 1995 were $1.79, $1.96 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 10,146 MMCF,
12,184 MMCF and 8,057 MMCF for the years ended December 31, 1995, 1994 and
1993, respectively. Hedged oil and condensate volumes were 498,000 BBLS,
370,000 BBLS and 720,000 BBLS for the years ended December 31, 1995, 1994
and 1993. The aggregate gains (losses) under energy swap agreements were
$3,536,000, $1,810,000 and $(2,050,000), respectively, for the years ended
December 31, 1995, 1994 and 1993.
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 royalty dispute and a payment
of deferred maintenance costs of a real estate complex formerly used for general
business purposes. Miscellaneous net revenue of $2,265,000 in 1993 included
$1,380,000 of interest income on short-term investments and an adjustment to
reduce accrued severance taxes based on discussions with the applicable state
taxing authorities.
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OIL AND GAS PRODUCTION EXPENSE. Oil and gas production expense increased
slightly to $22,463,000 in 1995 from $22,384,000 in 1994. On an MCFE basis,
production expense increased to $.56 per MCFE in 1995 from $.39 per MCFE in
1994. The increased cost per MCFE is directly attributable to fixed components
of oil and gas production expense being allocated over a smaller production
base. The Company expects production expense to decrease in 1996, on a per unit
basis, as a result of the Saxon and Canadian Forest acquisitions and increased
levels of capital investment. Oil and gas production expense increased 15% to
$22,384,000 in 1994 compared to $19,540,000 in 1993 due primarily to increased
natural gas production as a result of property acquisitions throughout 1993,
partially offset by a decrease in workover expenses and a general decrease in
expenses due to the sale of properties. In 1994 and 1993, production expense
was approximately $.39 on an MCFE basis.
GENERAL AND ADMINISTRATIVE EXPENSE. 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. General and administrative expense decreased 7% to $11,166,000 in 1994
compared to $12,003,000 in 1993. Decreases in salaries, wages and burden from
the termination of executives and middle level managers and increases in
production operation credits were partially offset by increases in insurance and
office and storage rental expenses. The capitalization rate remained relatively
constant from 1993 to 1995.
Total overhead costs, including amounts related to exploration and development
activities, were $15,857,000 in 1995, $18,719,000 in 1994 and $19,561,000 in
1993. 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 were due primarily to a reduction in the size of the
Company's workforce effective March 1, 1995. Excluding the severance and
employee relocation costs in 1993, which are described below, total overhead
costs were approximately 8% higher in 1994 than in 1993. This increase is
primarily due to an increase in storage rentals and higher insurance expense
attributable to a larger asset base, partially offset by a decrease in salaries,
wages and burden from the termination of executives and middle level managers.
Severance and employee relocation costs of approximately $2,300,000 in 1993
resulted from the termination of 10 executives and middle level managers and a
loss incurred on the sale of an employee's former residence in accordance with
the Company's relocation policy. The following table summarizes the total
overhead costs incurred during the periods:
Years Ended December 31,
---------------------------
1995 1994 1993
------- ------ ------
(In Thousands)
Overhead costs capitalized $ 6,776 7,553 7,558
General and administrative costs expensed 9,081 11,166 12,003
------- ------ ------
Total overhead costs $15,857 18,719 19,561(1)
------- ------ ------
------- ------ ------
(1) Includes approximately $2,300,000 of severance and employee relocation
costs.
INTEREST EXPENSE. 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.
Interest expense of $26,773,000 in 1994 increased $3,044,000 or 13% compared to
1993 due to higher loan balances as a result of borrowings for capital
expenditures.
DEPRECIATION AND DEPLETION EXPENSE. Depreciation and depletion expense
decreased 33% to $43,592,000 in 1995 from $65,468,000 in 1994 due to the
decrease in production, as well as a decrease in the depletion rate per unit of
production. The depletion rate decreased to $1.06 per MCFE for U.S. production
in 1995 compared to $1.13 for U.S. production in 1994 due to writedowns of the
Company's oil and gas properties taken in the third and fourth quarters of 1994.
Depreciation and depletion expense increased 8% to $65,468,000 in 1994 from
$60,581,000 in 1993 due to increased production in the 1994 period as a result
of property acquisitions. The depletion rate was $1.19 for U.S. production in
1993. At December 31, 1995, the Company had undeveloped properties with a cost
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basis of approximately $28,380,000 which were excluded from depletion compared
to $30,441,000 at December 31, 1994 and $41,216,000 at December 31, 1993. The
decrease from 1993 to 1994 and 1995 is attributable to exploration and
development work, as well as lease expirations and property sales.
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 1995 or 1993.
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.
Additional writedowns of the full cost pool may be required if prices decrease,
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.
The average Gulf Coast spot price received by the Company for natural gas
increased from $2.31 per MCF at December 31, 1995 to $2.83 per MCF at March 1,
1996. The West Texas Intermediate price for crude oil was $17.50 per barrel at
both December 31, 1995 and March 1, 1996.
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.
Statement of Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions," (SFAS No. 106) required the
Company to accrue expected costs of providing postretirement benefits to
employees and the employees' beneficiaries and covered dependents. The Company
adopted the provisions of SFAS No. 106 in the first quarter of 1993. The
estimated accumulated postretirement benefit obligation as of January 1, 1993
was approximately $4,822,000. This amount, reduced by applicable income tax
benefits, was charged to operations in the first quarter of 1993 as the
cumulative effect of a change in accounting principle. The annual net
postretirement benefit cost (included in total overhead costs) was approximately
$504,000 for 1995, $510,000 for 1994 and $483,000 for 1993.
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes," (SFAS No. 109), required the Company to adopt the liability method of
accounting for income taxes. The Company adopted such method on a prospective
basis as of January 1, 1993. The cumulative effect of adopting SFAS No. 109 as
of January 1, 1993 resulted in a reduction of the net amount of deferred income
taxes recorded as of December 31, 1992 of approximately $2,060,000. This amount
was credited to operations in the first quarter of 1993 as the cumulative effect
of a change in accounting principle.
In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS No. 121). SFAS
No. 121 is effective for fiscal years beginning after December 15, 1995. 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
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<PAGE>
disposed of. The Company will adopt SFAS No. 121 effective January 1, 1996.
The effect of such adoption is not expected to be material.
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 will include the disclosures
required by SFAS No. 123 in the notes to future financial statements.
LIQUIDITY AND CAPITAL RESOURCES
During 1995, the Company took various steps and committed to various actions to
improve its liquidity and capital resources. In early 1995, in response to
market conditions, the Company reduced its general and administrative
expenditures through a workforce reduction effective March 1, 1995. As a
result, total overhead for 1995 decreased by approximately $2,862,000 compared
to 1994 or by approximately 15%. In addition, the Company reduced its budgeted
capital expenditures during the first six months of 1995 to those required to
maintain its producing oil and gas properties as well as certain essential
development, drilling and other activities.
In July 1995, the Company received $45,000,000 of equity capital from Anschutz
and restructured the JEDI loan. As a result, the Company was able to resume its
capital expenditure program and to increase its levels of capital spending
during the last six months of 1995.
The Company completed two acquisitions of Canadian oil and gas companies, Saxon
in December 1995 and Canadian Forest in January 1996. For a description of
these transactions, see Item 1. Business "Operating Strategy." The Saxon
acquisition was financed using Forest Common Stock, cash and the transfer to
Saxon of shares of preferred stock of Archean Energy Ltd. The Canadian Forest
acquisition was financed through a public offering of Common Stock and
borrowings under the Company's Credit Facility.
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. On January 31, 1996,
the Company issued 13,200,000 shares of Common Stock 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 from the issuance of
the shares totalled approximately $125,600,000 after deducting issuance costs
and underwriting fees and were used, along with an additional approximately
$8,300,000 drawn from the Company's Credit Facility, to complete the purchase of
Canadian Forest.
The pro forma effect of the acquisitions and the public offering was to increase
total assets to $517,990,000 compared to $321,043,000 at December 31, 1995; to
increase shareholders' equity to $180,241,000 compared to $44,297,000 at
December 31, 1995; and to reduce the Company's debt-to-capitalization ratio to
53% compared to 98% at December 31, 1994.
As a result of the above, Forest's financial position and liquidity have
improved considerably. The Company expects to be able to meet its 1996 capital
expenditure financing requirements using cash flows generated by operations 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. 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.
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
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<PAGE>
and operational results. The Company continues to examine alternative sources
of long-term capital, including bank borrowings or the issuance of debt
instruments, the sale of production payments or other nonrecourse financing,
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.
CASH FLOW. Historically, one of the Company's primary sources of capital has
been net cash provided by operating activities (operating cash flow). During
1995, the Company's operating cash flow and working capital were adversely
affected by a significant decline in production. The following summary table
reflects comparative cash flow data for the Company for the years ended
December 31, 1995, 1994 and 1993.
Years Ended December 31,
----------------------------
1995 1994 1993
-------- ------- -------
(In Thousands)
Net cash provided (used) by operating
activities $ (3,062) 42,546 41,722
Net cash used by investing activities (17,219) (32,307) (170,134)
Net cash provided (used) by financing
activities 20,698 (14,231) 71,886
The Company experienced a net use of cash for operating activities of $3,062,000
in 1995 compared to $42,546,000 of net cash provided by operating activities in
the prior year as a result of lower production volumes, coupled with decreased
prices for natural gas. The Company used $17,219,000 for investing activities
in 1995 compared to $32,307,000 in the prior year due to lower direct capital
expenditures, offset in part by lower proceeds from property sales. Cash
provided by financing activities of $20,698,000 in 1995 included the net
proceeds from the issuance of stock and warrants to Anschutz, partially offset
by repayments of the Company's Credit Facility and a decrease in other
liabilities. In 1994, the Company used cash for financing activities of
$14,231,000, primarily consisting of the redemption of subordinated debentures
and a decrease in other liabilities, offset by borrowings under the Company's
Credit Facility.
WORKING CAPITAL. The Company had a working capital deficit of approximately
$9,181,000 at December 31, 1995 ($9,053,000 on a pro forma basis) compared to a
deficit of approximately $22,100,000 at December 31, 1994. The decrease in the
deficit is attributable primarily to a decrease in accounts payable related to
exploration and development costs.
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 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, 1995 the Company had borrowing capacity of approximately
$22,000,000 under its long-term bank credit facilities ($65,000,000 on a pro
forma basis). The Company's available credit at December 31, 1995 was adequate
to fund the working capital deficit at that date.
HEDGING PROGRAM. In addition to the volumes of natural gas and oil 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. 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, 1995, the Company had
natural gas swaps and collars (including those of Saxon) for an aggregate of
approximately 35.0 BBTU (billion British Thermal Units) per day of natural gas
during 1996 at fixed prices and floors ranging from $1.03 per MMBTU (million
British Thermal Units) on an Alberta
29
<PAGE>
Energy Company "C" (AECO "C" ) basis to $2.48 per MMBTU on a New York
Mercantile Exchange (NYMEX) basis and an aggregate of approximately 27.4 BBTU
per day of natural gas during 1997 at fixed prices and floors ranging from
$1.03 (AECO "C" basis) to $2.54 (NYMEX basis) per MMBTU. At December 31, 1995
the Company had oil swaps for an aggregate of 927 barrels per day of oil
during 1996 at fixed prices ranging from $16.70 to $17.90 (NYMEX basis). The
Company currently has no material oil swaps in place for 1997. For further
information on the Company's outstanding energy swaps, see Note 13 of Notes to
Consolidated Financial Statements.
CAPITAL EXPENDITURES. The Company's expenditures for property acquisition,
exploration and development for the past three years, were as follows:
Years Ended December 31,
----------------------------
1995 1994 1993
------- ------ -------
(In Thousands)
Property acquisition costs (1):
Proved properties $26,487 9,553 121,882
Undeveloped properties 320 209 23,034
------- ------ -------
26,807 9,762 144,916
Exploration costs:
Direct costs 11,528 15,229 4,923
Overhead capitalized 1,211 464 510
------- ------ -------
12,739 15,693 5,433
Development costs:
Direct costs 7,633 10,000 13,424
Overhead capitalized 5,565 7,089 7,048
------- ------ -------
13,198 17,089 20,472
------- ------ -------
$52,744 42,544 170,821
------- ------ -------
------- ------ -------
(1) 1995 amounts consist primarily of the allocation of purchase price to the
oil and gas properties acquired in the purchase of Saxon.
In 1995, the Company's property acquisition expenditures of $26,807,000 resulted
in proved reserve additions of an estimated 17.6 BCF of natural gas and
4,397,000 barrels of oil, as measured at the closing dates of the acquisitions
for financial accounting purposes. In 1994, the Company's property acquisition
expenditures of $9,762,000 resulted in proved reserve additions of an estimated
8.2 BCF of natural gas and 17,000 barrels of oil, as measured at the closing
dates of the acquisitions for financial accounting purposes. In 1993, the
Company's property acquisition expenditures of $144,916,000 resulted in proved
reserve additions of an estimated 94.7 BCF of natural gas and 1.7 million
barrels of oil, as measured at the closing dates, as well as eight exploitation
prospects and three exploratory offshore blocks.
The Company's 1996 budgeted expenditures for exploration and development are
approximately $20,500,000 and $41,500,000, respectively, including capitalized
overhead of approximately $7,500,000.
During 1996, the Company intends to continue a strategy of acquiring reserves
that meet its investment criteria; however, no assurance can be given that the
Company can locate or finance any property acquisitions. If adequate sources of
capital are not available to the Company in 1996, the amount invested in
exploration, development and reserve acquisitions will be required to be reduced
significantly.
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BANK CREDIT FACILITIES. 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
$40,000,000 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 proved oil and gas properties and related assets
(subject to prior security interests granted to holders of volumetric production
payment agreements), a pledge of accounts receivable, material contracts and the
stock of material subsidiaries. The maturity date of the Credit Facility is
July 1, 1998. 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, 1995 the outstanding balance under this facility was $23,800,000.
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 initial 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 Canadian Credit Facility has a three-
year term and 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.
In addition to the credit facilities described above, Saxon has a demand
revolving operating loan and a demand revolving production loan with borrowing
bases of $2,000,000 CDN and $20,000,000 CDN, respectively. The loans are
subject to semi-annual review and have 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, 1995 there
were outstanding borrowings of $929,000 CDN and $14,000,000 CDN under the
operating loan and the production loan, respectively. Saxon also had an
outstanding bridge loan at this date which was repaid in full using the proceeds
of the sale of the Forest Common Stock held by Saxon.
At February 29, 1996, the amount outstanding under the Credit Facility was
$8,300,000, the amount outstanding under the Canadian Credit Facility was
$44,680,000 CDN, and the amounts outstanding under the Saxon operating loan and
production loan were $1,267,000 CDN and $7,000,000 CDN, respectively.
Management believes the Company and Saxon will have adequate sources of short-
term liquidity to meet working capital needs, fund capital expenditures at
budgeted levels, and meet current debt service obligations.
OTHER FINANCING. Under the terms of volumetric production payments, 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. Amounts received for volumetric production payments are recorded as
deferred revenue, which is amortized as sales are recorded based upon the
scheduled deliveries under the production payment agreements. As of December
31, 1995, the volumes remaining to be delivered were approximately 8.0 BCF of
natural gas and 87,000 barrels of oil, and the related deferred revenue was
$15,137,000.
Under the terms of a nonrecourse secured loan from JEDI, the Company is required
to make payments based on the net proceeds, as defined, from certain subject
properties. The outstanding loan balance as of December 31, 1995 was
$40,322,000. Properties to which approximately 19% of the Company's estimated
proved reserves are attributable, on an MCFE equivalent basis, are dedicated to
repayment of the nonrecourse secured loan.
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<PAGE>
Under the terms of a production payment obligation, the Company must make a
monthly cash payment based on net proceeds from the subject properties. This
obligation has been recorded at a discount to reflect a market rate of interest.
At December 31, 1995 the remaining principal amount was $20,701,000 and the
recorded liability was $16,218,000. Properties to which approximately 6% of the
Company's estimated proved reserves are attributable, on an MCFE basis, are
dedicated to this production payment financing.
For further information on the Company's volumetric production payments,
nonrecourse secured loan, and production payment obligation, see Notes 5 and 6
of Notes to Consolidated Financial Statements.
ANSCHUTZ AND JEDI TRANSACTIONS. During 1995, following receipt of shareholder
approval, the Company consummated transactions with Anschutz and with JEDI.
Pursuant to a purchase agreement between the Company and Anschutz, Anschutz
purchased 3,760,000 shares of the Company's Common Stock and shares of a new
series of preferred stock that are convertible into 1,240,000 additional shares
of Common Stock for a total consideration of $45,000,000. In addition, Anschutz
received the A Warrant, which entitles it to purchase 3,888,888 shares of the
Company's Common Stock for $10.50 per share. The A Warrant expires on July 27,
1998. Anschutz also received from JEDI an option to purchase from JEDI up to
2,250,000 shares of Common Stock that JEDI had the right to acquire from the
Company upon exercise of the B Warrant referred to below (the Anschutz Option).
The Anschutz Option expires on July 27, 1998.
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 bears interest at the
rate of 12.5% per annum and is 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. In consideration, JEDI received the B
Warrant, which entitled it to purchase 2,250,000 shares of the Company's Common
Stock for $10.00 per share. JEDI also granted the Anschutz Option to Anschutz,
pursuant to which Anschutz was entitled to purchase from JEDI up to 2,250,000
shares 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. JEDI was to satisfy its obligations under the Anschutz Option by
exercising the B Warrant.
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 and annual interest expense by approximately $2,000,000. 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.
In December 1995, JEDI entered into an agreement to exchange the $22,400,000
tranche and the B Warrant for 1,680,000 shares of Common Stock (the JEDI
Exchange). As a result of the JEDI Exchange, the Company expects that non-cash
interest expense will be reduced by an additional $1,500,000 per year. The JEDI
Exchange also provided for other changes to the JEDI loan agreement that will
have the effect of increasing the Company's flexibility with respect to the
development of the properties securing the JEDI indebtedness.
Pursuant to the JEDI Exchange, the Company assumed JEDI's obligations under the
Anschutz Option. Under the Anschutz Option, the Company is now obligated to
issue shares directly to Anschutz that previously would have been issued to JEDI
pursuant to the B Warrant. Upon the exercise of the Anschutz Option, instead of
the B Warrant price of $10.00 per share, the Company will receive an amount
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 Company is permitted to use
proceeds from the exercise of the Anschutz Option for any corporate purpose.
For further information on the Anschutz and JEDI transactions, see Note 3 of
Notes to Consolidated Financial Statements.
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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.
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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, 1995 and 1994, 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, 1995.
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, 1995 and 1994, and the
results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 1995 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. As discussed in Notes 7
and 10 of Notes to Consolidated Financial Statements, the Company adopted the
provisions of Financial Accounting Standards Board Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" and Statement of
Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" in 1993.
KPMG PEAT MARWICK LLP
Denver, Colorado
February 20, 1996
34
<PAGE>
FOREST OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
Pro Forma
1995 (Note 2) December 31,
(Unaudited) 1995 1994
----------- -------- --------
(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 3,287 3,287 2,869
Accounts receivable 35,763 17,395 20,418
Other current assets 4,612 2,557 2,231
-------- -------- --------
Total current assets 43,662 23,239 25,518
Net property and equipment, at cost (Note 5) 429,584 277,599 276,609
Investment in affiliate (Note 4) 11,301 11,301 11,652
Other assets 33,443 8,904 11,053
-------- -------- --------
$517,990 321,043 324,832
-------- -------- --------
-------- -------- --------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Cash overdraft $ 2,055 2,055 4,445
Current portion of long-term debt (Note 5) 2,263 2,263 1,636
Current portion of gas balancing liability 4,700 4,700 5,735
Accounts payable 37,561 17,456 26,557
Accrued interest 4,219 4,029 4,318
Other current liabilities 1,917 1,917 4,927
-------- -------- --------
Total current liabilities 52,715 32,420 47,618
Commitments and contingencies (Notes 10,
12 and 13)
Long-term debt (Notes 3 and 5) 192,848 193,879 207,054
Gas balancing liability 3,841 3,841 8,525
Other liabilities 25,824 23,298 19,641
Deferred revenue (Note 6) 15,137 15,137 35,908
Deferred income taxes 38,502 - -
Minority interest (Note 2) 8,882 8,171 -
Shareholders' equity (Notes 2, 3, 5, 8 and 9):
Preferred stock 24,359 24,359 15,845
Common stock, 10,660,291 shares in 1995
(22,800,291 shares pro forma, and
5,659,042 shares in 1994) 2,280 1,066 566
Capital surplus 366,431 241,241 192,337
Common shares to be issued in debt
restructuring 6,073 6,073 -
Accumulated deficit (217,495) (217,495) (199,499)
Foreign currency translation (1,407) (1,407) (1,337)
Treasury stock, at cost, 1,060,000 shares in
1995 and 21,188 shares in 1994 - (9,540) (1,826)
-------- -------- --------
Total shareholders' equity 180,241 44,297 6,086
-------- -------- --------
$517,990 321,043 324,832
-------- -------- --------
-------- -------- --------
See accompanying Notes to Consolidated Financial Statements.
35
<PAGE>
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
Years Ended December 31,
1995 1994 1993
-------- -------- --------
(In Thousands Except Per Share Amounts)
<S> <C> <C> <C>
Revenue:
Oil and gas sales:
Gas $ 59,084 91,309 77,249
Gas contract settlement (Note 15) 4,263 - -
Oil and condensate 18,602 22,874 25,341
Products and other 326 358 293
-------- -------- --------
82,275 114,541 102,883
Miscellaneous, net 181 1,406 2,265
-------- -------- --------
Total revenue 82,456 115,947 105,148
Expenses:
Oil and gas production 22,463 22,384 19,540
General and administrative 9,081 11,166 12,003
Interest 25,323 26,773 23,729
Depreciation and depletion 43,592 65,468 60,581
Provision for impairment of oil and gas properties - 58,000 -
-------- -------- --------
Total expenses 100,459 183,791 115,853
-------- -------- --------
Loss before income taxes, cumulative effects of changes in
accounting principles and extraordinary item (18,003) (67,844) (10,705)
Income tax expense (benefit) (Note 7):
Current (7) 9 254
Deferred - - (1,604)
-------- -------- --------
(7) 9 (1,350)
-------- -------- --------
Loss before cumulative effects of changes in
accounting principles and extraordinary item (17,996) (67,853) (9,355)
Cumulative effects of changes in accounting principles:
Oil and gas sales (Note 1) - (13,990) -
Postretirement benefits, net of income tax benefit of $1,639,000 (Note 10) - - (3,183)
Income taxes (Note 7) - - 2,060
-------- -------- --------
- (13,990) (1,123)
-------- -------- --------
Loss before extraordinary item (17,996) (81,843) (10,478)
Extraordinary item - loss on extinguishment of debt, net of income tax
benefit of $4,652,000 (Note 5) - - (10,735)
Net loss $(17,996) (81,843) (21,213)
-------- -------- --------
-------- -------- --------
Weighted average number of common shares outstanding 7,360 5,619 4,399
-------- -------- --------
-------- -------- --------
Net loss attributable to common stock $(20,156) (84,004) (23,463)
-------- -------- --------
-------- -------- --------
Pro forma amounts assuming the change in accounting for
oil and gas sales is applied retroactively:
Loss before cumulative effects of changes in
accounting principles and extraordinary item $ (3,962)
--------
--------
Net loss $(15,820)
--------
--------
</TABLE>
(continued on following page)
36
<PAGE>
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (CONTINUED)
<TABLE>
Years Ended December 31,
1995 1994 1993
---- ---- ----
(In Thousands Except Per Share Amounts)
<S> <C> <C> <C>
Primary and fully diluted loss per common share:
Loss before cumulative effects of changes in accounting
principles and extraordinary item $ (2.74) (12.46) (2.64)
Cumulative effects of changes in accounting principles - (2.49) (.26)
-------- ------ ------
Loss before extraordinary item (2.74) (14.95) (2.90)
Extraordinary item - loss on extinguishment of debt - - (2.44)
-------- ------ ------
Net loss attributable to common stock $ (2.74) (14.95) (5.34)
-------- ------ ------
-------- ------ ------
Pro forma amounts assuming the change in accounting for oil and
gas sales is applied retroactively:
Primary and fully diluted loss per common share:
Loss before cumulative effects of changes in
accounting principles and extraordinary item $ (1.41)
-------
-------
Net loss attributable to common stock $ (4.11)
-------
-------
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
37
<PAGE>
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
<TABLE>
Common
Common Shares to be
Stock and Issued Accumu- Foreign
Preferred Class B Capital in Debt lated Currency Treasury
Stock Stock Surplus Restructuring Deficit Translation Stock
--------- --------- ------- ------------- -------- ----------- --------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Balance December 31, 1992 $17,214 300 146,592 - (96,443) (427) (7,355)
Net loss - - - - (21,213) - -
Issuance of common stock, net of
offering costs (Note 9) - 222 51,284 - - - -
$.75 Convertible Preferred Stock
dividends paid in common
stock (Note 8) - 13 (13) - - - -
Conversion of $.75 Convertible
Preferred Stock to common stock
(Note 8) (1,369) 17 1,352 - - - -
Reclassification of Class B to
common stock (Note 9) - 7 (7) - - - -
Exercise of employee stock options
(Note 9) - 3 393 - - - -
Common stock issued and treasury
stock contributed to the Retirement
Savings Plan and other (Note 10) - 3 (586) - - - 1,565
Unfunded pension liability (Note 10) - - (3,038) - - - -
Foreign currency translation - - - - - (358) -
------- ----- ------- ----- -------- ------ ------
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
Retirement 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
(NOTES 3 AND 9) - 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) - - 8,311 - - - -
ISSUANCE OF WARRANTS TO JEDI
(NOTES 3 AND 9) - - 12,116 - - - -
COSTS ASSOCIATED WITH EQUITY ISSUED
TO ANSCHUTZ AND JEDI - - (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 DEBT
RESTRUCTURING (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)
------- ----- ------- ----- -------- ------ ------
------- ----- ------- ----- -------- ------ ------
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
38
<PAGE>
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
Years Ended December 31,
-------------------------------
1995 1994 1993
-------- ------- --------
(In Thousands)
<S> <C> <C> <C>
Cash flows from operating activities:
Loss before cumulative effects of changes in
accounting principles and extraordinary item $(17,996) (67,853) (9,355)
Adjustments to reconcile loss before cumulative effects of
changes in accounting principles and extraordinary item
to net cash provided (used) by operating activities:
Depreciation and depletion 43,592 65,468 60,581
Provision for impairment of oil and gas properties - 58,000 -
Deferred Federal income tax benefit - - (1,604)
Other, net 3,303 5,372 3,045
Decrease in accounts receivable 4,285 4,839 2,264
(Increase) decrease in other current assets (152) 1,078 375
Increase (decrease) in accounts payable (11,458) 4,021 (12,668)
Increase (decrease) in accrued interest and other
current liabilities (3,865) 2,941 (1,078)
Proceeds from volumetric production payments - 4,353 40,468
Amortization of deferred revenue (20,771) (35,673) (40,306)
-------- ------- --------
Net cash provided (used) by operating activities (3,062) 42,546 41,722
Cash flows from investing activities:
Capital expenditures for property and equipment (27,098) (42,780) (171,166)
Cash paid for acquisition of subsidiary (1,121) - -
Proceeds of sales of property and equipment, net 8,715 12,941 2,997
Decrease (increase) in other assets, net 2,285 (2,468) (1,965)
-------- ------- --------
Net cash used by investing activities (17,219) (32,307) (170,134)
Cash flows from financing activities:
Proceeds from bank borrowings 82,600 31,500 25,000
Repayments of bank borrowings (91,800) (23,500) -
Proceeds from nonrecourse secured loan - 1,400 57,400
Repayments of nonrecourse secured loan (1,143) - -
Repayments of production payment obligation (2,316) (2,771) (5,980)
Issuance of senior subordinated notes, net of offering costs - - 95,827
Redemptions and repurchases of subordinated debentures
and secured notes - (7,171) (148,918)
Proceeds from capital stock and warrants issued, net of
issuance costs 41,060 - 51,506
Payment of preferred stock dividends (540) (2,161) -
Debt issuance costs (491) (772) (1,336)
Increase (decrease) in cash overdraft (2,390) 551 (1,347)
Decrease in other liabilities, net (4,282) (11,307) (266)
-------- ------- --------
Net cash provided (used) by financing activities 20,698 (14,231) 71,886
Effect of exchange rate changes on cash 1 (88) (12)
-------- ------- --------
Net increase (decrease) in cash and cash equivalents 418 (4,080) (56,538)
Cash and cash equivalents at beginning of year 2,869 6,949 63,487
-------- ------- --------
Cash and cash equivalents at end of year $ 3,287 2,869 6,949
-------- ------- --------
-------- ------- --------
Cash paid during the year for:
Interest $ 22,138 23,989 23,123
-------- ------- --------
-------- ------- --------
Income taxes $ - 9 452
-------- ------- --------
-------- ------- --------
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
39
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(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,
following two recent acquisitions, in Canada.
The consolidated financial statements include the accounts of Forest Oil
Corporation and its subsidiaries (Forest or the Company). Significant
intercompany balances and transactions are eliminated. 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. During 1995, 1994 and 1993, the Company's oil and gas
operations were conducted 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 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, 1995, 1994 and 1993, there were undeveloped
property costs of $28,380,000, $30,441,000 and $41,216,000, respectively, in the
United States which were not being depleted. Of the undeveloped costs not being
depleted at December 31, 1995, approximately 20% were incurred in 1995, 4% in
1994, 71% in 1993 and 5% in 1992.
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 the
years ended December 31, 1995, 1994 and 1993 was $1.06, $1.13 and $1.19,
respectively.
Pursuant to full cost accounting rules, capitalized costs less related
accumulated depletion and deferred income taxes 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 1994. There was no impairment of oil and gas property costs in
1995 or 1993.
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.
40
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED):
- ------------------------------------------------------------------------------
Net property and equipment at December 31 consists of the following:
1995 1994
---- ----
(In Thousands)
Oil and gas properties $1,216,027 1,171,887
Buildings, transportation and
other equipment 10,502 12,649
---------- ---------
1,226,529 1,184,536
Less accumulated depreciation,
depletion and valuation allowance 948,930 907,927
---------- ---------
$ 277,599 276,609
---------- ---------
---------- ---------
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.
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. The pro
forma amounts shown on the consolidated statements of operations have been
adjusted for the effect of the retroactive application of the change, including
the related income tax effects.
As of December 31, 1995 the Company had produced approximately 5 BCF more than
its entitled share of production. The estimated value of this imbalance of
approximately $8,541,000 is included in the accompanying consolidated balance
sheet as a short-term liability of $4,700,000 and a long-term liability of
$3,841,000.
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. Gains
and losses related to these hedging transactions are recognized as adjustments
to revenue recorded for the related production. Costs associated with the
purchase of certain hedge instruments are deferred and amortized against revenue
related to hedged production.
INCOME TAXES - The adoption of Statement of Financial Accounting Standards No.
109, "Accounting for Income Taxes" (SFAS No. 109), effective January 1, 1993
changed the Company's method of accounting for income taxes from the deferred
method to an asset and liability method. Previously, the Company deferred the
tax effects of timing differences between financial reporting and taxable
income. The asset and liability method 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.
41
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED):
- -------------------------------------------------------------------------------
FOREIGN CURRENCY TRANSLATION - Assets and liabilities related to Canadian
investments 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 $2,160,000 in 1995, $2,161,000 in 1994 and $2,250,000 in 1993.
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 debentures were converted at the beginning of each
period or date of issuance, if later, with earnings being increased for interest
expense, net of taxes, that would not have been incurred had conversion taken
place, (ii) that convertible preferred stock was converted at the beginning of
each period or date of issuance, if later, and (iii) any additional dilutive
effect of stock options and warrants. The effects of these assumptions were
anti-dilutive in 1995, 1994 and 1993.
RECLASSIFICATIONS - Certain amounts in the 1994 and 1993 financial statements
have been reclassified to conform to the 1995 financial statement presentation.
(2) ACQUISITIONS:
- -------------------------------------------------------------------------------
In May and December, 1993, the Company purchased interests in properties from
Atlantic Richfield Company (ARCO) for approximately $60,862,000. In conjunction
with the ARCO acquisitions, the Company sold volumetric production payments from
certain of the ARCO properties for approximately $40,468,000 (net of fees). In
December 1993, the Company purchased interests in offshore properties for
approximately $24,050,000 and interests in properties in south Texas for
approximately $59,458,000. In conjunction with these acquisitions, the Company
entered into a nonrecourse secured loan agreement for $51,600,000.
The Company's results of operations include the effects of the first ARCO
acquisition since May 1, 1993, the offshore properties and the second ARCO
acquisition since December 1, 1993 and the south Texas properties since January
1, 1994.
During 1994, the Company completed acquisitions totaling $9,762,000, including
additional interests in properties acquired in 1993. In order to finance one of
the acquisitions, the Company sold a volumetric production payment for
approximately $4,353,000 (net of fees).
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. 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. 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 prices of the shares immediately preceding the announcement of the
acquisition less a discount of 20%, or $9.00 per share. The discount applied
reflects the fact that the shares were not registered and not freely tradable,
that there were certain restrictions placed on the shares as a condition of the
purchase agreement, and that the shares represented a large block of Forest
common stock.
42
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(2) ACQUISITIONS (CONTINUED):
- -------------------------------------------------------------------------------
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.
Saxon is a Canadian exploration and production company with headquarters in
Calgary, Alberta and operations concentrated in western Alberta. Saxon had
estimated proved reserves at December 31, 1995 of 16.2 BCF of natural gas and
4.3 million barrels of oil.
Forest has the ability to convert its preferred shares and its nonvoting common
shares of Saxon into voting common shares at any time. As a result, Forest has
financial control over Saxon and has accounted for Saxon as a consolidated
subsidiary. The consolidated balance sheet of Forest includes the accounts of
Saxon at December 31, 1995. The Company has not recorded 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 are not significant.
On January 31, 1996 the Company completed the acquisition of ATCOR Resources
Ltd. of Calgary, Alberta for approximately $134,900,000, exclusive of
acquisition costs of approximately $1,800,000. 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. At December 31, 1995 Canadian Forest had estimated proved reserves of
92.0 BCF of natural gas and 10.2 million barrels of oil.
As part of the Canadian Forest acquisition, Forest also acquired ATCOR's natural
gas marketing business which was renamed Producers Marketing Ltd. (ProMark).
The pro forma consolidated balance sheet at December 31, 1995 gives effect to
the public offering of common stock and the Canadian Forest acquisition as if
both had occurred on that date. The following pro forma consolidated statement
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, 1995
--------------------
(In Thousands Except
Per Share Amounts)
Revenue:
Oil and gas sales $ 129,778
Marketing and processing 139,815
Miscellaneous, net 188
---------
Total revenue $ 269,781
---------
---------
Loss before income taxes,
cumulative effect of changes in
accounting principles and
extraordinary item $ (7,768)
---------
---------
Net loss $ (14,117)
---------
---------
Primary and fully diluted
loss per share $ (.73)
---------
---------
43
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(3) ANSCHUTZ AND JEDI TRANSACTIONS:
- -------------------------------------------------------------------------------
During 1995, following receipt of shareholder approval, 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 that are convertible into 1,240,000 additional
shares of common stock for a total consideration of $45,000,000. The preferred
stock has a liquidation preference of $18.00 per share and receives dividends
ratably with the common stock. In addition, Anschutz received a warrant that
entitles it to purchase 3,888,888 shares of the Company's common stock for
$10.50 per share (the A Warrant). The A Warrant expires 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 ($8,311,000) issued. At the
second closing, Anschutz also received from JEDI an option to purchase from JEDI
up to 2,250,000 shares of common stock that JEDI had the right to acquire from
the Company upon exercise of the B Warrant referred to below (the Anschutz
Option). The Anschutz Option terminates on July 27, 1998. The Company has
entered into a shareholders agreement with Anschutz pursuant to which Anschutz
agreed to certain voting, acquisition, and transfer limitations regarding shares
of common stock for five years after the second closing.
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 bears interest at the rate of 12.5% per annum and is 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 warrants 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, less the estimated brokerage fees on the ultimate
disposition of the shares.
Also at the second closing, JEDI granted the Anschutz Option to Anschutz,
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. 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 is 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 is now obligated
to issue shares directly to Anschutz that previously would have been issued
to JEDI pursuant to the B Warrant. Upon the exercise of the Anschutz
44
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(3) ANSCHUTZ AND JEDI TRANSACTIONS (CONTINUED):
- -------------------------------------------------------------------------------
Option, instead of the original B Warrant price of $10.00 per share, the Company
will receive an amount 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 Company is permitted to use proceeds from the exercise of the Anschutz
Option for any corporate purpose. Pursuant to the JEDI Exchange, JEDI entered
into a shareholders agreement with the Company that limits JEDI's right to vote
its shares of common stock and, except in certain circumstances, to transfer its
shares before July 27, 1998.
(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 1995, 1994 or 1993.
In December, 1995, in connection with the Saxon acquisition, the Company
transferred its Archean preferred stock to Saxon. In consolidation, the Company
is accounting for the investment in Archean at its historical carrying value.
(5) LONG-TERM DEBT:
- -------------------------------------------------------------------------------
Long-term debt at December 31 for the years presented consists of the following:
1995 1994
-------- -------
Credit facility $ 23,800 33,000
Saxon credit facilities 16,437 -
Nonrecourse secured loan 40,322 57,840
Production payment obligation 16,218 18,534
11-1/4% Senior Subordinated Notes 99,365 99,316
-------- ------
196,142 208,690
Less current portion (2,263) (1,636)
-------- -------
Long-term debt $193,879 207,054
-------- -------
-------- -------
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 $40,000,000 for working
capital and/or general corporate purposes. Advances under this facility bear
interest at rates ranging from the banks' prime rate plus 1/4% to prime plus 1%
or, alternatively, Eurodollar prime plus 1 1/2% to prime plus 2 1/4% depending
on amounts outstanding under the Credit Facility. The borrowing base is subject
to formal redetermination semi-annually, but may be changed at the banks'
discretion at any time.
45
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(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), a pledge of accounts receivable, material
contracts and the stock of material subsidiaries. The maturity date of the
Credit Facility is July 1, 1998. 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, 1995, notes
payable of $23,800,000 were outstanding under the Credit Facility with interest
at rates ranging from 7.38% to 9.0% per annum. The Company has also used the
Credit Facility for a $1,500,000 letter of credit.
SAXON CREDIT FACILITIES
At December 31, 1995, Saxon has credit facilities with Canadian banks which
include a demand revolving operating loan, a demand revolving production loan
and a bridge loan.
The operating loan facility has a borrowing base of $2,000,000 CDN. Advances
made under this facility bear interest at the bank prime rate and are secured by
a fixed and floating charge debenture and a general assignment of book debts.
The loan is subject to semi-annual review and has a demand feature; 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, 1995 the amount outstanding under the operating loan facility was $929,000
CDN and the interest rate was 8 1/4%.
The production loan facility has a borrowing base of $20,000,000 CDN. Advances
made under this facility bear interest at the bank prime rate or the bankers
acceptance rate plus a stamping fee at the option of the Company and are secured
by a fixed and floating charge debenture and a general assignment of book debts.
The loan is subject to semi-annual review and has a demand feature; 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, 1995 the amount outstanding under the production loan facility was
$14,000,000 CDN and the interest rate was 8 1/2%.
The bridge loan of $7,500,000 CDN outstanding at December 31, 1995 was a term
loan due December 18, 1996. The loan bore interest at the bank prime rate plus
1 1/2% (9% at December 31, 1995) and was secured by Saxon's marketable
securities, including its shares of Forest common stock.
On January 31, 1996, using proceeds from the sale of its Forest common stock,
Saxon repaid the bridge loan and reduced the balance outstanding under the
production loan.
CANADIAN 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 initial 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 Canadian Credit Facility has a three-
year term and is indirectly secured by substantially all the assets of Canadian
Forest. 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.
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
is required to make payments based on the net proceeds, as defined, from certain
subject properties. Payments under the JEDI loan are due monthly and are equal
to 90% of total net operating income from the secured properties, reduced by 80%
of allowable capital expenditures, as defined.
46
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(5) LONG-TERM DEBT (CONTINUED):
- -------------------------------------------------------------------------------
Under the restructured loan, the Company is required to pay interest at 12.5%
per annum on the outstanding loan balance. Payments are applied first to
interest and then to principal. Principal payments will be applied to reduce
the outstanding balance as will the proceeds, if any, from the exercise of the A
Warrant. The outstanding loan balance as of December 31, 1995, was $40,322,000.
The Company's current estimate, based on expected production and prices and
budgeted capital expenditure levels, is that the liability will increase by
approximately $4,018,000 in 1996 and $812,000 in 1997, and that the liability
will decrease by approximately $10,756,000 in 1998, $12,314,000 in 1999, and
$13,772,000 in 2000. Properties to which approximately 19% of the Company's
estimated proved reserves are attributable, on an MCFE equivalent basis, are
dedicated to repayment of the JEDI loan.
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, 1995
the remaining principal amount was $20,701,000 and the recorded liability was
$16,218,000. 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, 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 1996 payments will reduce the recorded liability by approximately
$1,942,000, which amount is included in current liabilities, and by
approximately $1,931,000 in 1997, $1,002,000 in 1998, $3,824,000 in 1999 and
$3,235,000 in 2000. Properties to which approximately 6% 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 Company used the net proceeds from the sale of the
Senior Subordinated Notes of approximately $95,827,000, together with
approximately $19,400,000 of available cash, to redeem all of its outstanding
Senior Secured Notes and long-term subordinated debentures. The redemptions
resulted in a loss of $15,387,000 which was recorded as an extraordinary loss of
$10,735,000 (net of income tax benefit of $4,652,000).
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 9, 2000 and at 100%
thereafter. In addition, the Company may, at its option, redeem prior to
September 1, 1996 up to 30% of the initially outstanding principal amount of the
Notes at 110% of the principal amount thereof, plus accrued interest to the date
of redemption, with the net proceeds of any future public offering of its common
stock.
Under the terms of the Senior Subordinated Notes, the Company must meet certain
tests before it is able to pay cash dividends (other than dividends on the
Company's $.75 Convertible Preferred Stock) 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 Secured 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.
47
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(6) DEFERRED REVENUE:
- -------------------------------------------------------------------------------
From April 1991 through May 1993, the Company entered into four volumetric
production payments with entities affiliated with Enron for net proceeds of
$121,498,000. Under the terms of these production payments, the Company was
required to deliver 70.1 bcf of natural gas and 770,000 barrels of oil over
periods ranging from three to six years.
Effective November 1, 1993, the four separate volumetric payment financings
described above between the Company and Enron were consolidated into one
production payment. The delivery schedules from the previously separate
production payments were not adjusted; however, delivery shortfalls on any
property can now be made up from excess production from any other property which
is dedicated to the production payment obligation. The consolidation also
provided that certain acreage previously committed to the production payments
was released and can be developed by the Company unburdened by the delivery
obligations of the production payment.
In connection with the purchase of interests in properties from ARCO in December
1993, a volumetric production payment from certain of the ARCO properties was
sold to Enron for net proceeds of $13,207,000. This production payment covered
approximately 7.3 BCF of natural gas to be delivered over 8 years.
In July 1994, the Company purchased additional interests in the properties
acquired from ARCO in December 1993. In connection with this transaction, a
volumetric production payment was sold to Enron for net proceeds of $4,353,000.
This production payment covered approximately 2.7 BCF of natural gas to be
delivered over 8 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, 1995, 1994 and 1993 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)
----------- ------- ----------- -------
1995 11,045 173 9,120 145
1994 19,985 218 16,005 182
1993 23,392 221 18,731 185
(1) Amounts settled in cash in lieu of volumes were $1,276,000, $1,611,381
and $3,138,628 for the years ended December 31, 1995, 1994, and 1993,
respectively.
(2) Represents volumes required to be delivered to Enron affiliates net of
estimated royalty volumes.
48
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(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
Attributable to
Volumes Required to be Production Payment
Delivered to Enron Deliveries (1)
---------------------- ---------------------
Annual Natural Gas Oil Natural Gas Oil
Amortization (MMCF) (MBBLS) (MMCF) (MBBLS)
------------ ----------- ------- ----------- -------
(In Thousands)
1996 $ 7,546 3,721 87 2,895 74
1997 2,439 1,410 - 1,097 -
1998 1,592 892 - 694 -
THEREAFTER 3,560 1,994 - 1,552 -
------- ----- -- ----- --
$15,137 8,017 87 6,238 74
------- ----- -- ----- --
------- ----- -- ----- --
(1) Represents volumes required to be delivered to Enron net of estimated
royalty volumes.
(7) INCOME TAXES:
- -------------------------------------------------------------------------------
The Company adopted Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes," (SFAS No. 109) on a prospective basis effective
January 1, 1993. The cumulative effect of this change in accounting for income
taxes of $2,060,000 was determined as of January 1, 1993 and was reported
separately in the consolidated statement of operations for the year ended
December 31, 1993.
The income tax expense (benefit) is different from amounts computed by applying
the statutory Federal income tax rate for the following reasons:
1995 1994 1993
------- ------- ------
(In Thousands)
Tax benefit at 35% of loss before
income taxes, cumulative effects of
changes in accounting principles and
extraordinary item $(6,367) (23,749) (3,747)
Change in the balance of the valuation
allowance for deferred tax assets
attributable to loss before income
taxes, cumulative effects of changes
in accounting principles and
extraordinary item 5,732 23,220 2,034
Expiration of tax carryforwards 535 455 318
Other 93 83 45
------- ------- ------
Total income tax expense (benefit) $ (7) 9 (1,350)
------- ------- ------
------- ------- ------
Deferred income taxes generally result from recognizing income and expenses at
different times for financial and tax reporting. These 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.
49
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(7) INCOME TAXES:
- -------------------------------------------------------------------------------
The components of the net deferred tax liability at December 31, 1995 and 1994
are as follows:
1995 1994
--------- -------
(In Thousands)
Deferred tax assets:
Allowance for doubtful accounts $ 283 308
Accrual for retirement benefits 1,229 1,447
Accrual for medical benefits 2,216 2,037
Accrual for sales recorded on
the entitlements method 2,990 3,642
Net operating loss carryforward 39,204 21,976
Depletion carryforward 6,958 6,958
Investment tax credit carryforward 3,219 3,674
Alternative minimum tax credit
carryforward 2,206 2,206
Other 375 455
-------- -------
Total gross deferred tax assets 58,680 42,703
Less valuation allowance (46,524) (40,792)
-------- -------
Net deferred tax assets 12,156 1,911
Deferred tax liabilities:
Oil and gas properties, due to full
cost method of accounting (12,156) (1,911)
-------- -------
Net deferred tax liability $ - -
-------- -------
-------- -------
The net change in the total valuation allowance for the year ended December 31,
1995 was an increase of $5,732,000.
The Alternative Minimum Tax (AMT) credit carryforward available to reduce future
Federal regular taxes aggregated $2,206,000 at December 31, 1995. This amount
may be carried forward indefinitely. Regular and AMT net operating loss
carryforwards at December 31, 1995 were $112,015,000 and $109,779,000,
respectively, and will expire in the years indicated below:
Regular AMT
-------- -------
(In Thousands)
2000 $ 2,665 4,143
2005 8,307 -
2008 28,999 31,800
2009 22,817 22,964
2010 49,227 50,872
-------- -------
$112,015 109,779
-------- -------
-------- -------
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 Federal income
taxes aggregated $3,219,000 at December 31, 1995 and expire at various dates
through the year 2001. Percentage depletion carryforwards available to reduce
future Federal taxable income aggregated $19,879,000 at December 31, 1995. This
amount may be carried forward indefinitely.
The availability of some of these tax attributes to reduce current and future
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. Under the general provisions of
50
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(7) INCOME TAXES (CONTINUED):
- -------------------------------------------------------------------------------
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.
(8) PREFERRED STOCK:
- -------------------------------------------------------------------------------
$.75 CONVERTIBLE PREFERRED STOCK:
The Company has 10,000,000 shares of $.75 Convertible Preferred Stock
authorized, par value $.01 per share, of which there were 2,880,173 shares
outstanding at December 31, 1995 and 2,880,973 shares outstanding at December
31, 1994, with an aggregate liquidation preference of $28,801,730 at December
31, 1995 and $28,809,730 at December 31, 1994. This stock is 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 1995, 800 shares of $.75 Convertible
Preferred Stock were converted into 560 shares of common stock; there were no
conversions in 1994; and during 1993, 248,817 shares of $.75 Convertible
Preferred Stock were converted into 174,172 shares of common stock. The $.75
Convertible Preferred Stock is redeemable, in whole or in part, at the option of
the Company, at any time after the earlier of (i) July 1, 1996 or (ii) the date
on which the last reported sales price of the common stock will have been $37.50
or higher for at least 20 of the prior 30 trading days, at a redemption price of
$10.17 per share during the twelve-month period which began July 1, 1995 and
declining to $10.00 per share at July 1, 1996 and thereafter, including
accumulated and unpaid dividends. Cumulative annual dividends of $.75 per share
are 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 may 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
after the February 1, 1995 dividend due to restrictions contained in the Credit
Facility with its lending banks. Under the terms of the $.75 Convertible
Preferred Stock, common stock delivered in payment of dividends is 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 are in arrears, no dividends
or distributions, except for dividends paid in shares of common stock, may
be paid or declared on the common stock, nor may any shares of common stock
be acquired by the Company.
SECOND SERIES PREFERRED STOCK:
The Company has 620,000 shares of Second Series Preferred Stock authorized, par
value $.01 per share, of which there were 620,000 shares outstanding at December
31, 1995, with an aggregate liquidation preference of $11,160,000 at December
31, 1995. Each share of Second Series Preferred Stock (1) is convertible into 2
shares of Common Stock, which conversion may be made from time to time on or
before July 27, 2000, but which in any event shall be made on July 27, 2000, (2)
has no right to vote, (3) has the right to receive dividends on the dates and in
the form that dividends are payable on the common stock, in each case in an
amount equal to the amount of
51
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(8) PREFERRED STOCK (CONTINUED):
- ------------------------------------------------------------------------------
such dividend payable on the number of shares of common stock into which such
share of Second Series Preferred Stock shall be convertible immediately
preceding the record date for the determination of the shareholders entitled to
receive such dividend, and (4) has 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, has the right to receive
distributions on the dates and in the form that distributions are payable on the
common stock, in each case in an amount equal to the amount of such
distributions payable on the number of shares of common stock into which such
share of Second Series Preferred Stock is convertible (assuming for such purpose
that such conversion were possible) immediately preceding the record date for
the determination of the shareholders entitled to receive such distribution.
the rights of the holders of the Second Series Preferred Stock to receive
dividends are junior and subordinate to the rights of the holders of the $.75
Convertible Preferred Stock to the same extent that the rights of the holders of
the common stock are subordinate in right to receive dividends to the rights of
the holders of the $.75 Convertible Preferred Stock to receive dividends, and
the rights of the holders of the Second Series Preferred Stock rank pari passu
with the Company's $.75 Convertible Preferred Stock as to liquidation
preference.
(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.
There were 10,660,291 and 5,659,042 shares of common stock issued at December
31, 1995 and 1994, respectively, with 1,060,000 and 21,188 shares held by the
Company as treasury shares at December 31, 1995 and 1994, respectively. The
common stock is entitled to one vote per share. Prior to May 1993 the Company
also had Class B stock which had superior voting rights to the Company's common
stock, had limited transferability and was not traded in any public market but
was convertible at any time into shares of common stock on a share-for-share
basis. The Company's Restated Certificate of Incorporation was amended on May
12, 1993 to reclassify each share of Class B Stock into 1.1 shares of common
stock.
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 from the
issuance of shares totalled approximately $125,600,000 after deducting issuance
costs and underwriting fees.
On June 15, 1993 the Company issued 2,216,000 shares of common stock for $25.00
per share in a public offering. The net proceeds from the issuance of the
shares totalled approximately $51,506,000 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
52
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(9) COMMON STOCK (CONTINUED):
- ------------------------------------------------------------------------------
acquired pursuant to the conversion of the Second Series Preferred Stock or the
exercise of the A Warrant or 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:
The Company has outstanding 1,244,715 warrants to purchase shares of its common
stock (the Public Warrants). Each Public Warrant entitles the holder to
purchase one-fifth share of common stock at a price of $3.00, is non-callable
and expires on October 1, 1996.
The Company has outstanding the A Warrant that is held by Anschutz. The A
Warrant entitles the holder to purchase 3,888,888 shares of common stock at a
price of $10.50 per share and expires on July 27, 1998.
In December 1995, the Company assumed JEDI's obligations under an option to
purchase 2,250,000 shares of common stock (the Anschutz Option). Upon the
exercise of the Anschutz Option, the Company will receive an amount 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 expires on
July 27, 1998.
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. A summary of stock
option activity related to the Plan is as follows:
Option Price
Shares Per Share
------ ---------
Options outstanding at December 31, 1992 348,000 $ 15.00
Granted 305,000 25.00
Exercised (26,400) 15.00
Cancelled or surrendered (15,800) 15.00
------- ------------
Options outstanding at December 31, 1993 610,800 $15.00-25.00
Granted 62,000 25.00
Exercised (7,000) 15.00
Cancelled or surrendered (7,000) 25.00
------- ------------
Options outstanding at December 31, 1994 658,800 $15.00-25.00
GRANTED - -
EXERCISED - -
CANCELLED OR SURRENDERED (30,800) -
------- ------------
OPTIONS OUTSTANDING AT DECEMBER 31, 1995 628,000 $15.00-25.00
------- ------------
------- ------------
OPTIONS EXERCISABLE AT DECEMBER 31, 1995 461,200 $15.00-25.00
------- ------------
------- ------------
53
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(9) COMMON STOCK (CONTINUED):
- ------------------------------------------------------------------------------
On February 1, 1996 the Company offered option holders employed by the Company
the opportunity to surrender their existing options exercisable at $15.00 to
$25.00 per share in exchange for options exercisable at $11.25 per share.
Pursuant to this offer, options to purchase 491,800 shares of common stock at
$15.00 to $25.00 per share were cancelled and options to purchase 474,400 shares
at $11.25 per share were granted. Concurrently, the Company granted certain
employees additional options to purchase 99,000 shares at $11.25 per share.
(10) EMPLOYEE BENEFITS
- ------------------------------------------------------------------------------
PENSION PLANS
The Company has a qualified defined benefit pension plan (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 1995, 1994 or 1993.
The following table sets forth the Pension Plan's funded status and amounts
recognized in the Company's consolidated financial statements at December 31:
1995 1994
---- ----
(In Thousands)
Actuarial present value of accumulated benefit
obligation (all benefits are vested) $(27,485) (23,953)
-------- -------
-------- -------
Projected benefit obligation for service
rendered to date $(27,485) (23,953)
Plan assets at fair market value, consisting
primarily of listed stocks, bonds and other
fixed income obligations 24,270 23,443
-------- -------
Unfunded pension liability (3,215) (510)
Unrecognized net loss from past experience
different from that assumed and effects of
changes in assumptions 4,133 1,468
-------- -------
Pension asset recognized in the balance sheet $ 918 958
-------- -------
-------- -------
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%. For 1993, the discount rate
used in determining the actuarial present value of the projected benefit
obligation was 7.5% 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,
1995, 1994 and 1993 are as follows:
1995 1994 1993
---- ---- ----
(In Thousands)
Net pension expense (benefit) included the
following components:
Interest cost on projected benefit obligation $ 2,049 1,976 2,039
Actual return on plan assets (3,243) (245) (3,534)
Net amortization and deferral 1,234 (1,955) 1,441
------- ------ ------
Net pension expense (benefit) $ 40 (224) (54)
------- ------ ------
------- ------ ------
54
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(10) EMPLOYEE BENEFITS (CONTINUED):
- ------------------------------------------------------------------------------
The Company has a non-qualified unfunded supplementary retirement plan that
provides certain officers with defined retirement benefits in excess of
qualified plan limits imposed by Federal tax law. Benefit accruals under this
plan were suspended effective May 31, 1991 in connection with suspension of
benefit accruals under the Pension Plan. At December 31, 1995 the projected
benefit obligation under this plan totaled $639,000, 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 the increase in the discount
rate for the Pension Plan and the supplementary retirement plan in 1994, the
Company reduced the liability representing the unfunded pension liability by
approximately $1,570,000, with a corresponding increase in capital surplus.
As a result of the decrease in the discount rate for the Pension Plan and the
supplementary retirement plan in 1995, the Company increased the liability
representing the pension liability by approximately $2,836,000, with a
corresponding decrease in capital surplus.
RETIREMENT SAVINGS PLAN:
The Company sponsors a qualified tax deferred savings plan in accordance with
the provisions of Section 401(k) of the Internal Revenue Code. 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 and 1993, Company contributions were
made using treasury stock. In the last six months of 1995, Company
contributions were made by issuing authorized but unissued shares. The expense
associated with the Company's contribution was $423,000 in 1995, $516,000 in
1994 and $367,000 in 1993.
Effective January 1, 1992 the plan was amended to include profit-sharing
contributions by the Company. In 1995 and 1994, the Company did not make any
profit sharing contributions. The Company's profit-sharing contributions were
made using common stock valued at $276,000 in 1993.
ANNUAL INCENTIVE PLAN:
The Forest Oil Corporation Annual Incentive Plan (the Incentive Plan), which
became effective January 1, 1992, permitted participating employees to earn
annual bonus awards payable in cash or in shares of the Company's Common Stock,
generally based in part upon the Company attaining certain levels of
performance. In 1995 and 1994, no bonuses were awarded. In 1993, the Company
accrued bonuses of $426,000 under the incentive plan. Amounts awarded are
disbursed in equal annual installments over the succeeding three-year period.
This plan was terminated effective January 1, 1996.
EXECUTIVE RETIREMENT AGREEMENTS:
The Company entered into agreements in December 1990 (the Agreements) with
certain former executives and directors (the Retirees) whereby each executive
retired from the employ of the Company as of December 28, 1990. Pursuant to
the terms of the Agreements, the Retirees are entitled to receive
supplemental retirement payments from the Company in addition to the amounts
to which they are entitled under the Company's retirement plan. In addition,
the Retirees and their spouses are entitled to lifetime coverage under the
Company's group medical and dental plans, tax and other financial services,
and payments by the Company in connection with certain club membership dues.
The Retirees also continued to participate in the Company's royalty bonus
program until December 31, 1995. The Company has also agreed to maintain
certain life insurance policies in effect at December 1990, for the benefit
of each of the Retirees.
The Company's obligation to one retiree under a revised retirement agreement
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 totalling approximately
$970,000 per year through 1998 and approximately $770,000 per year in 1999
and 2000.
55
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(10) EMPLOYEE BENEFITS (CONTINUED):
- -------------------------------------------------------------------------------
The $3,617,000 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 paid for the
life insurance policies were $921,000, $916,000 and $861,000 in 1995, 1994
and 1993, respectively, including $831,000, $831,000 and $766,000 paid 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
Company adopted the provisions of SFAS No. 106 in the first quarter of 1993.
The estimated accumulated postretirement benefit obligation as of January 1,
1993 was approximately $4,822,000. This amount, reduced by applicable income
tax benefits, was charged to operations in the first quarter of 1993 as the
cumulative effect of a change in accounting principle.
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:
1995 1994
---- ----
(In Thousands)
Retired participants $4,803 4,427
Active participants fully eligible for benefits 201 156
Other active participants 1,026 873
------ ------
Accumulated postretirement benefit obligation (APBO) 6,030 5,456
Plan assets at fair market value - -
------ ------
APBO in excess of plan assets 6,030 5,456
Unrecognized loss (595) (330)
------ ------
Accrued postretirement benefit liability $ 5,435 5,126
------ ------
------ ------
The discount rates used in determining the actuarial present value of the
APBO at December 31, 1995, 1994 and 1993 were 7.25%, 9% and 7.5%,
respectively.
The components of postretirement benefit expense for the years ended December
31, 1995, 1994 and 1993 are as follows:
1995 1994 1993
---- ---- ----
(In Thousands)
Service cost $ 83 103 86
Interest cost on APBO 421 407 397
---- ---- ----
Postretirement benefit cost $ 504 510 483
---- ---- ----
---- ---- ----
For 1995, a 1% increase in health care cost trends would have increased the
APBO by $793,000 and the service interest costs by $62,000.
56
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(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. The company incurred expenses for its use of
the complex of $635,000 in 1993.
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 $1,154,000, $962,000, $953,000,
$985,000 and $851,000 for the years ending December 31, 1996 through 2000,
respectively. These amounts include future rentals payable by Saxon.
Net rental payments applicable to exploration and development activities and
capitalized in the oil and gas property accounts aggregated $972,000 in 1995,
$851,000 in 1994 and $688,000 in 1993. Net rental payments charged to expense
amounted to $3,529,000 in 1995, $3,512,000 in 1994 and $3,098,000 in 1993.
Rental payments include the short-term lease of vehicles. none of the leases
are accounted for as capital leases.
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.
57
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(13) FINANCIAL INSTRUMENTS:
- -------------------------------------------------------------------------------
The Company is exposed to off-balance-sheet risks associated with energy swap
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
agreements.
In order to hedge against the effects 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, 1995,
1994 and 1993, the Company's gains (losses) under its swap agreements were
$3,536,000, $1,810,000 and $(2,050,000) respectively.
The following table indicates outstanding energy swaps of the Company at
December 31, 1995:
Product Volume Fixed Price Duration
------- ------ ----------- --------
Natural Gas 194 to 7,091 MMBTU/day $2.1875 to $2.535 1/96 - 12/99
Natural Gas 10,000 MMBTU/day $2.00 to $2.37 1/96 - 12/97
Natural Gas 100 to 300 MMBTU/day $2.1855 to $3.003 1/96 - 12/02
Natural Gas 5,000 to 10,000 MMBTU/day $1.90 to $2.0225 1/96 - 12/96
Natural Gas 5,000 MMBTU/day $1.9225 4/96 - 12/96
Natural Gas 1,500 to 2,000 MMBTU/day $1.0282 (1) 1/96 - 6/98
Oil 661 BBLS/day $16.70 1/96 - 4/96
Oil 659 BBLS/day $17.75 1/96 - 6/96
Oil 332 BBLS/day $17.90 5/96 - 12/96
Oil 325 BBLS/day $16.7345 1/96 - 6/96
(1) Based on Alberta Energy Company "C" (AECO "C") basis. All other swaps
are settled on the basis of New York Mercantile Exchange (NYMEX) prices.
58
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(13) FINANCIAL INSTRUMENTS (CONTINUED):
- -------------------------------------------------------------------------------
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, 1995:
CASH AND CASH EQUIVALENTS, ACCOUNTS RECEIVABLES AND ACCOUNTS PAYABLE:
The carrying amount of these instruments approximates fair value due to their
short maturity.
NONRECOURSE SECURED LOAN:
The fair value of the Company's nonrecourse secured loan has been estimated
as approximately $43,147,000 by discounting the projected future cash
payments required under the agreement by 10.5%.
PRODUCTION PAYMENT OBLIGATION:
The fair value of the Company's production payment obligation has been
estimated as approximately $15,188,000 by discounting the projected future
cash payments required under the agreement by 10.5%.
SENIOR SUBORDINATED NOTES:
The fair value of the Company's 11 1/4% Senior Subordinated Notes was
approximately $104,000,000, based upon quoted market prices of the Notes.
ENERGY SWAP AGREEMENTS:
The fair value of the Company's energy swap agreements was approximately
$1,007,000, based upon the estimated net amount the Company would have to pay
to terminate the agreements.
(14) MAJOR CUSTOMERS:
- -------------------------------------------------------------------------------
The Company's sales of oil and natural gas to individual customers which
exceeded 10% of the Company's total sales (exclusive of the effects of energy
swaps and hedges) were:
1995 1994 1993
---- ---- ----
(In Thousands)
Enron Affiliates (A) $30,916 58,805 63,075
Chevron USA Production Company 11,893 12,829 -
(A) The amount shown for Enron Affiliates includes oil and natural gas sales to
Enron Gas Marketing Inc., Enron Oil & Gas Company, EOTT Energy Corporation,
Cactus Funding Corporation, Cactus Hydrocarbon III Limited Partnership,
Enron Gas Services Corporation and Enron Reserve Acquisition.
Approximately $17,217,000, $29,046,000 and $32,702,000 represent sales
recorded for deliveries under volumetric production payments in the years
ended December 31, 1995, 1994 and 1993, 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.
59
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(16) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED):
- -------------------------------------------------------------------------------
<TABLE>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------
(In Thousands Except Per Share Amounts)
<S> <C> <C> <C> <C>
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)
-------- ------ ------ ------
-------- ------ ------ ------
1994
- ----
Revenue $ 32,543 32,977 28,207 22,220
-------- ------ ------ ------
-------- ------ ------ ------
Earnings from operations $ 24,241 23,600 19,387 13,763
-------- ------ ------ ------
-------- ------ ------ ------
Income (loss) before cumulative effects
of changes in accounting principles
and extraordinary item $ 236 (265) (32,873) (34,951)
-------- ------ ------ ------
-------- ------ ------ ------
Net loss $(13,754) (265) (32,873) (34,951)
-------- ------ ------ ------
-------- ------ ------ ------
Net loss attributable to common stock $(14,294) (805) (33,414) (35,491)
-------- ------ ------ ------
-------- ------ ------ ------
Primary and fully diluted loss per share
before cumulative effects of changes
in accounting principles and
extraordinary item $ (.05) (.14) (5.94) (6.30)
-------- ------ ------ ------
-------- ------ ------ ------
Primary and fully diluted loss per share $ (2.55) (.14) (5.94) (6.30)
-------- ------ ------ ------
-------- ------ ------ ------
</TABLE>
60
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED):
- --------------------------------------------------------------------------------
The following information is presented in accordance with Statement of
Financial Accounting Standards No. 69, "Disclosure about Oil and Gas
Producing Activities," (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, 1995, 1994 and 1993:
UNITED
STATES CANADA TOTAL
------ ------ -----
(In Thousands)
1995
- ----
PROPERTY ACQUISITION COSTS (UNDEVELOPED
LEASES AND PROVED PROPERTIES) $ 844 25,963 (1) 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
-------- ------ -------
-------- ------ -------
1993
- ----
Property acquisition costs (undeveloped
leases and proved properties) $144,916 - 144,916
Exploration costs 5,433 - 5,433
Development costs 20,472 - 20,472
-------- ------ -------
Total $170,821 - 170,821
-------- ------ -------
-------- ------ -------
(1) Consists of the allocation of purchase price to 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 were incurred as of December 31 of the years indicated:
1995 1994 1993
---- ---- ----
(In Thousands)
Costs related to proved properties $1,169,636 1,109,158 1,066,855
Costs related to unproved properties:
Costs subject to depletion 18,011 32,288 32,585
Costs not subject to depletion 28,380 30,441 41,216
---------- --------- ---------
1,216,027 1,171,887 1,140,656
Less accumulated depletion and
valuation allowance 941,482 895,335 778,226
---------- --------- ---------
$ 274,545 276,552 362,430
---------- --------- ---------
---------- --------- ---------
61
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- --------------------------------------------------------------------------------
(C) RESULTS OF OPERATIONS FROM PRODUCING ACTIVITIES - Results of operations
from producing activities for 1995, 1994 and 1993 are presented below.
1995 1994 1993
---- ---- ----
(In Thousands)
Oil and gas sales $82,275 114,541 102,883
Production expense 22,463 22,384 19,540
Depletion expense 42,973 64,883 59,759
Provision for impairment of oil and
gas properties - 58,000 -
------- ------- -------
65,436 145,267 79,299
------- ------- -------
Results of operations from producing
activities $16,839 (30,726) 23,584
------- ------- -------
------- ------- -------
(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 1993, 1994 and 1995 follows. The Canadian reserves at December 31,
1995 represent 100% of the reserves owned by Saxon, a consolidated subsidiary in
which the Company holds a 56% economic 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.
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. 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.
62
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- --------------------------------------------------------------------------------
<TABLE>
LIQUIDS GAS
------------------------------ ------------------------------
(MBBLS) (MMCF)
UNITED UNITED
STATES CANADA TOTAL STATES CANADA TOTAL
------ ------ ----- ------ ------ -----
<S> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1992 6,973 - 6,973 164,421 - 164,421
Revisions of previous estimates 507 - 507 17,874 - 17,874
Extensions and discoveries 201 - 201 8,395 - 8,395
Production (1,308) - (1,308) (22,383) - (22,383)
Sales of reserves in place (280) - (280) (18,941) - (18,941)
Purchases of reserves in place 1,704 - 1,704 94,730 - 94,730
------ ------ ------ ------- ------- -------
Balance at December 31, 1993 7,797 - 7,797 244,096 - 244,096
Additional disclosures:
Volumes attributable to volumetric
production payments 401 - 401 29,286 - 29,286
------ ------ ------ ------- ------- -------
Balance at December 31, 1993, including
volumes attributable to volumetric
production payments 8,198 - 8,198 273,382 - 273,382
------ ------ ------ ------- ------- -------
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
ADDITIONAL DISCLOSURES:
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
------ ------ ------ ------- ------- -------
------ ------ ------ ------- ------- -------
PRO FORMA RESERVES, INCLUDING VOLUMES
ATTRIBUTABLE TO VOLUMETRIC PRODUCTION PAYMENTS,
AFTER GIVING EFFECT TO THE CANADIAN FOREST
ACQUISITION (SEE NOTE 2) 6,203 14,585 20,788 221,910 108,256 330,166
------ ------ ------ ------- ------- -------
------ ------ ------ ------- ------- -------
</TABLE>
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.
63
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- --------------------------------------------------------------------------------
(D) ESTIMATED PROVED OIL AND GAS RESERVES (CONTINUED)
<TABLE>
<CAPTION>
Oil and Condensate Gas
-------------------------- -----------------------------
(MBBLS) (MMCF)
United United
States Canada Total States Canada Total
------ ------ ----- ------ ------ -----
<S> <C> <C> <C> <C> <C> <C>
Proved developed reserves at:
December 31, 1992 5,831 - 5,831 146,048 - 146,048
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 4,184 170,655
Pro forma proved developed reserves
after giving effect to the
Canadian Forest acquisition
(see Note 2) 5,678 13,435 19,113 156,471 106,222 262,693
</TABLE>
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.
<TABLE>
<CAPTION>
Oil and Condensate Gas
-------------------------- -----------------------------
(MBBLS) (MMCF)
United United
States Canada Total States Canada Total
------ ------ ----- ------ ------ -----
<S> <C> <C> <C> <C> <C> <C>
Proved developed reserves, including
amounts attributable to volumetric
production payments at:
December 31, 1992 6,418 - 6,418 176,282 - 176,282
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
Pro forma proved developed reserves,
including amounts attributable
to volumetric production
payments after giving effect
to the Canadian Forest
acquisition (see Note 2) 5,752 13,435 19,187 162,709 106,222 268,931
</TABLE>
(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, 1995, Canadian
disclosures represents 100% of amounts attributable to the reserves owned by
Saxon, a consolidated subsidiary in which the Company holds a 56% economic
interest. All of the estimated reserves at December 31, 1994 and 1993 were in
the United States. 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.
64
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- --------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
Future income tax expenses are estimated using the statutory tax rate of 35%.
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 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.
<TABLE>
<CAPTION>
December 31, 1995
---------------------------------
United
States Canada Total
------ ------ -----
(In Thousands)
<S> <C> <C> <C>
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
-------- -------- --------
-------- -------- --------
Pro forma standardized measure of discounted future net
cash flows, including amounts attributable to
volumetric production payments, after giving
effect to the Canadian Forest acquisition (see Note 2) $236,303 105,849 342,152
-------- -------- --------
-------- -------- --------
</TABLE>
65
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- --------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
Undiscounted future income tax expense was $22,316,000 in the United States and
$2,924,000 in Canada at December 31, 1995.
<TABLE>
<CAPTION>
December 31,
1994 1993
---- ----
(In Thousands)
<S> <C> <C>
Future oil and gas sales $502,186 662,265
Future production and development costs (193,376) (240,145)
-------- --------
Future net revenue 308,810 422,120
10% annual discount for estimated timing of cash flows (100,480) (138,917)
-------- --------
Present value of future net cash flows before income taxes 208,330 283,203
Present value of future income tax expense (781) (21,027)
-------- --------
Standardized measure of discounted future net cash flows 207,549 262,176
Additional disclosures:
Amounts attributable to volumetric production payments 22,600 36,877
-------- --------
Total discounted future net cash flows, including amounts
attributable to volumetric production payments $230,149 299,053
-------- --------
-------- --------
</TABLE>
Undiscounted future income tax expense was $1,348,000 at December 31, 1994 and
$35,028,000 at December 31, 1993.
66
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- --------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING
TO PROVED OIL AND GAS RESERVES - An analysis of the changes in the standardized
measure of discounted future net cash flows during each of the last three years
is as follows. At December 31, 1995, Canadian disclosures represent amounts
attributable to 100% of the reserves owned by Saxon, a consolidated subsidiary
in which the Company holds a 56% economic interest. All of the estimated
reserves at December 31, 1994 and 1993 were in the United States.
<TABLE>
<CAPTION>
December 31, 1995
---------------------------------
United
States Canada Total
------ ------ -----
<S> <C> <C> <C>
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
-------- ------- -------
-------- ------- -------
Proforma standardized measure of discounted future net
cash flows, including amounts attributable to
volumetric production payments, after giving effect to
the Canadian Forest acquisition (see Note 2) $236,303 105,849 342,152
-------- ------- -------
-------- ------- -------
</TABLE>
67
<PAGE>
FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
(17) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(CONTINUED):
- --------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (CONTINUED)
<TABLE>
<CAPTION>
1994 1993
---- ----
(In Thousands)
<S> <C> <C>
Standardized measure of discounted future net cash flows relating
to proved oil and gas reserves, at beginning of year $262,176 190,971
Changes resulting from:
Sales of oil and gas, net of production costs (69,607) (59,572)
Net changes in prices and future production costs (80,526) (22,010)
Net changes in future development costs 7,432 (18,724)
Extensions, discoveries and improved recovery 10,817 15,322
Previously estimated development costs incurred during the period 10,000 13,424
Revisions of previous quantity estimates 16,840 25,262
Sales of reserves in place (10,630) (28,802)
Purchases of reserves in place 8,467 127,418
Accretion of discount on reserves at beginning of year before
income taxes 32,334 24,558
Net change in income taxes 20,246 (5,671)
-------- -------
Standardized measure of discounted future net cash flows relating
to proved oil and gas reserves, at end of year 207,549 262,176
Additional disclosures:
Amounts attributable to volumetric production payments 22,600 36,877
-------- -------
Total discounted future net cash flows relating to proved
oil and gas reserves, including amounts attributable to
volumetric production payments, at end of year $230,149 299,053
-------- -------
-------- -------
</TABLE>
68
<PAGE>
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, 1995 and
1994
3. Consolidated Statements of Operations - Years ended
December 31, 1995, 1994 and 1993
4. Consolidated Statements of Shareholders' Equity -
Years ended December 31, 1995, 1994 and 1993
5. Consolidated Statements of Cash Flows - Years ended
December 31, 1995, 1994 and 1993
6. Notes to Consolidated Financial Statements - Years
ended December 31, 1995, 1994 and 1993
(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).
69
<PAGE>
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).
Exhibit 4.3 Loan Agreement between Forest Oil Corporation and Joint
Energy Development Investments Limited Partnership dated as
of December 28, 1993, incorporated herein by reference to
Exhibit 4.1 to Form 8-K for Forest Oil Corporation dated
December 30, 1993 (File No. 0-4597).
Exhibit 4.4 First Amendment dated as of December 28, 1993 to the Loan
Agreement between Forest Oil Corporation and Joint Energy
Development Investments Limited Partnership, incorporated
herein by reference to Exhibit 4.3 to Form 10-Q for Forest
Oil Corporation for the quarter ended June 30, 1994 (File
No. 0-4597).
Exhibit 4.5 Second Amendment dated as of July 27, 1995 to the Loan
Agreement between Forest Oil Corporation and Joint Energy
Development Investments Limited Partnership, incorporated by
reference to Exhibit 99.4 to Form 8-K for Forest Oil
Corporation dated October 11, 1995 (File No. 0-4597).
Exhibit 4.6 Third Amendment dated January 24, 1996 to the Loan Agreement
between Forest Oil Corporation and Joint Energy Development
Investments Limited Partnership.
70
<PAGE>
Exhibit 4.7 Deed of Trust, Assignment of Production, Security Agreement
and Financing Statement dated as of December 28, 1993 by and
between Forest Oil Corporation and Joint Energy Development
Investments Limited Partnership, incorporated herein by
reference to Exhibit 4.2 to Form 8-K for Forest Oil
Corporation dated December 30, 1993 (File No. 0-4597).
Exhibit 4.8 First Amendment dated as of June 15, 1994 to the Deed of
Trust, Assignment of Production, Security Agreement and
Financing Statement between Forest Oil Corporation and Joint
Energy Development Investments Limited Partnership,
incorporated herein by reference to Exhibit 4.4 to Form 10-Q
for Forest Oil Corporation for the quarter ended June 30,
1994 (File No. 0-4597).
Exhibit 4.9 Second Amendment effective as of July 27, 1995 to Deed of
Trust, Assignment of Production, Security Agreement and
Financing Statement between Forest Oil Corporation and Joint
Energy Development Investments Limited Partnership,
incorporated herein by reference to Exhibit 99.9 to Form 8-K
for Forest Oil Corporation dated October 11, 1995 (File No.
0-4597).
Exhibit 4.10 Act of Mortgage, Assignment of Production, Security
Agreement and Financing Statement dated as of December 28,
1993 between Forest Oil Corporation and Joint Energy
Development Investments Limited Partnership, incorporated
herein by reference to Exhibit 4.3 to Form 8-K for Forest
Oil Corporation dated December 30, 1993 (File No. 0-4597).
Exhibit 4.11 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 4.12 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.
Exhibit 4.13 Amendment No. 1 dated as of June 3, 1994 to the Deed of
Trust, Mortgage, Security Agreement, Assignment of
Production, Financing Statement (Personal Property including
Hydrocarbons) and Fixture Filing dated as of December 1,
1993 between Forest Oil Corporation and The Chase Manhattan
Bank (National Association), as agent, incorporated herein
by reference to Exhibit 4.9 of Form 10-K for Forest Oil
Corporation for the year ended December 31, 1994 (File No.
0-4597).
Exhibit 4.14 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.
Exhibit 4.15 Deed of Trust, Mortgage, Security Agreement, Assignment of
Production, Financing Statement (Personal Property including
Hydrocarbons) and Fixture Filing dated as of June 3, 1994
between Forest Oil Corporation and The Chase Manhattan Bank
(National Association), as agent, incorporated herein by
reference to Exhibit 4.9 of Form 10-K for Forest Oil
Corporation for the year ended December 31, 1994 (File No.
0-4597).
Exhibit 4.16 Amendment No. 1 dated as of August 31, 1995 to Deed of
Trust, Mortgage, Security Agreement, Assignment of
Production, Financing Statement (Personal Property Including
Hydrocarbons), and Fixture Filing dated June 3, 1994.
71
<PAGE>
Exhibit 4.17 Warrant Agreement dated as of December 3, 1991 between
Forest Oil Corporation and The Chase Manhattan Bank
(National Association), as Warrant Agent (including Form of
Warrant), incorporated herein by reference to Exhibit 4.7 to
Form 10-K for Forest Oil Corporation for the year ended
December 31, 1991 (File No. 0-4597).
Exhibit 4.18 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 4.19 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 Employee Overriding Royalty Bonuses,
incorporated herein by reference to Exhibit 10.1 to Form 10-K
for Forest Oil Corporation for the year ended December 31,
1990 (File No. 0-4597).
Exhibit 10.2 Description of Executive Life Insurance Plan, incorporated
herein by reference to Exhibit 10.2 to Form 10-K for Forest
Oil Corporation for the year ended December 31, 1991 (File
No. 0-4597).
Exhibit 10.3 Form of non-qualified Executive Deferred Compensation
Agreement, incorporated herein by reference to Exhibit 10.3
to Form 10-Q for Forest Oil Corporation for the years ended
December 31, 1990 (File No. 0-4597).
Exhibit 10.4 Form of non-qualified Supplemental Executive Retirement
Plan, incorporated herein by reference to Exhibit 10.4 to
Form 10-K for Forest Oil Corporation for the year ended
December 31, 1990 (File No. 0-4597).
Exhibit 10.5 Form of Executive Retirement Agreement, incorporated herein
by reference to Exhibit 10.5 to Form 10-K for Forest Oil
Corporation for the year ended December 31, 1990 (File No.
0-4597).
Exhibit 10.6 Forest Oil Corporation 1992 Stock Option Plan and Option
Agreement, incorporated herein by reference to Exhibit 10.7
to Form 10-K for Forest Oil Corporation for the year ended
December 31, 1991 (File No. 0-4597).
Exhibit 10.7 Letter Agreement with Richard B. Dorn relating to a revision
to Exhibit 10.5, incorporated herein by reference to Exhibit
10.11 to Form 10-K for Forest Oil Corporation for the year
ended December 31, 1991 (File No. 0-4597).
Exhibit 10.8 Forest Oil Corporation Annual Incentive Plan effective as of
January 1, 1992, incorporated herein by reference to Exhibit
10.8 to Form 10-K for Forest Oil Corporation for the year
ended December 31, 1992 (File No. 0-4597).
Exhibit 10.9 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 10.10 Shareholders Agreement dated as of July 27, 1995 between
Forest Oil Corporation and The Anschutz Corporation
incorporated by reference to Exhibit 99.7 to Form 8-K for
Forest Oil Corporation dated October 11, 1995 (File
No. 0-4597).
Exhibit 10.11 Tranche A Warrant to Purchase 3,888,888 shares of Common
Stock issued to The Anschutz Corporation dated July 27, 1995
incorporated by reference to Exhibit 99.6 to Form 8-K for
Forest Oil Corporation dated October 11, 1995 (File
No. 0-4597).
72
<PAGE>
Exhibit 10.12 Shareholders Agreement dated as of January 24, 1996 between
Forest Oil Corporation and Joint Energy Development
Investments Limited Partnership.
Exhibit 10.13 Option dated July 27, 1995 from Joint energy Development
Investments Limited Partnership to The Anschutz Corporation.
Exhibit 10.14 Assumption of Option dated January 24, 1996 between Forest
Oil Corporation and The Anschutz Corporation.
Exhibit 11 Computation of Earnings Per Share of Common Stock. Forest
Oil Corporation and Subsidiaries.
Exhibit 21.1 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, Richard J. Callahan,
Dale F. Dorn, William L. Dorn, 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 1995:
Date of Report Item Reported Financial Statements Filed
-------------- ------------- --------------------------
October 11, 1995 Item 5 None
December 12, 1995 Item 5 None
December 20, 1995 Item 5 None
December 29, 1995 Item 5 None
73
<PAGE>
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: January 28, 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 Officer March 29, 1996
(Robert S. Boswell) (Principal Executive Officer)
David H. Keyte* Vice President and Chief Financial Officer March 29, 1996
(David H. Keyte) (Principal Financial Officer)
Joan C. Sonnen* Controller March 29, 1996
(Joan C. Sonnen) (Chief Accounting Officer)
Philip F. Anschutz* Directors of the Registrant March 29, 1996
(Philip F. Anschutz)
Robert S. Boswell*
(Robert S. Boswell)
Richard J. Callahan*
(Richard J. Callahan)
Dale F. Dorn*
(Dale F. Dorn)
William L. Dorn*
(William L. Dorn)
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 29, 1996
---------------------------------
Daniel L. McNamara
(as attorney-in-fact for
each of the persons indicated)
74
<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT AUDITORS
THE BOARD OF DIRECTORS
FOREST OIL CORPORATION
We consent to the incorporation by reference in (i) the Registration
Statements (Nos. 2-74151, 2-76946, 33-2748 and 33-59504) on Form S-8 of
Forest Oil Corporation - Retirement Savings Plan of Forest Oil Corporation,
(ii) the Registration Statement (No. 33-48440) on Form S-8 of Forest Oil
Corporation -1992 Stock Option Plan of Forest Oil Corporation and (iii) the
Registration Statements (Nos. 33-47477 and 33-47478) on Forms S-2 and S-3 of
Forest Oil Corporation - Common Stock issuable to Richard Dorn and resales
thereof, of our report dated February 20, 1996 relating to the consolidated
balance sheets of Forest Oil Corporation and subsidiaries as of December 31,
1995 and 1994, 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, 1995, which report appears in the December 31, 1995
annual report on Form 10-K of Forest Oil Corporation.
Our report on the consolidated financial statements refers to a change in the
method of accounting for oil and gas sales from the sales method to the
entitlements method effective January 1, 1994 and to changes in the method of
accounting for postretirement benefits other than pensions and income taxes
in 1993.
KPMG PEAT MARWICK LLP
Denver, Colorado
January 28, 1997
