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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
(Mark One)
/ X / ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 (Fee Required)
For the fiscal year ended December 31, 1993
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
1500 Colorado National Building
950 - 17th Street
Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 303-592-2400
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS
Common Stock, Par Value $.10 Per Share
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. /X/
The aggregate market value of the voting stock held by persons other than
officers and directors of the registrant was approximately $111,051,174 as of
January 31, 1994 (based on the last sale price of such stock as quoted on the
National Market System of NASDAQ System).
There were 27,942,755 shares of the registrant's Common Stock, Par Value
$.10 Per Share outstanding as of February 28, 1994.
Document incorporated by reference: Proxy Statement of Forest Oil
Corporation relative to the Annual Meeting of Shareholders to be held on
May 11, 1994, which is incorporated into Part III of this Form 10-K.
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TABLE OF CONTENTS
Page No.
----------
PART I
Item 1. Business 1
Item 2. Properties 7
Item 3. Legal Proceedings 12
Item 4. Submission of Matters to a Vote of
Security Holders 13
Item 4A. Executive Officers of Forest 13
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 15
Item 6. Selected Financial and Operating Data 19
Item 7. Management's Discussion and Analysis
of Financial Condition and
Results of Operations 20
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 65
Item 11. Executive Compensation 65
Item 12. Security Ownership of Certain Beneficial
Owners and Management 65
Item 13. Certain Relationships and Related
Transactions 65
PART IV
Item 14. Exhibits, Financial Statement Schedules
and Reports on Form 8-K 65
PART I
ITEM 1. BUSINESS
THE COMPANY
Forest Oil Corporation and its subsidiaries (Forest or the Company) are
engaged in the acquisition and exploitation of, exploration for and
development and production of oil and natural gas. 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. Forest's principal reserves and producing properties are
located in the Gulf of Mexico and in Texas, Oklahoma and Wyoming.
The Company operates from production offices located in Lafayette, Louisiana
and Denver, Colorado. Its corporate offices are located in Denver, Colorado.
On December 31, 1993, Forest had 187 employees, of whom 129 were salaried and
58 were hourly.
OPERATING STRATEGY
In 1991, Forest adopted a new operating strategy which focuses primarily on
acquiring domestic reserves that have significant exploitation potential,
increasing production from existing fields through the application of the
Company's technical and operating expertise and participating in exploration
through farmout arrangements. The Company believes that it has competitive
advantages with respect to acquiring and exploiting properties because of its
technical and operating expertise, its seismic data base and its ability to
operate both onshore and offshore. The Company seeks to acquire interests in
properties in which it would have a significant working interest and which it
can operate. Since 1991, the Company has implemented its operating strategy
by acquiring estimated proved reserves of approximately 181 BCF of natural
gas and 8 million barrels of oil and condensate at an average property
acquisition cost of $1.08 per MCFE through December 31, 1993. (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 oil to 6 MCF of natural gas. With respect
to oil, the term BBL means one barrel of oil whereas MBBLS is used to
designate one thousand barrels of oil.)
During 1993, the Company completed four major acquisitions. In two separate
transactions completed in May 1993 and December 1993, the Company purchased
interests in two onshore fields and seven offshore blocks from Atlantic
Richfield Company (ARCO) for approximately $60,862,000. Total estimated
proved reserves acquired in the ARCO acquisitions were 40.1 BCF of natural
gas and 1.3 million barrels of oil. The ARCO acquisitions were financed in
part by volumetric production payments. In December 1993, the Company
purchased interests in two producing offshore fields in the West Cameron and
Eugene Island areas (the West Cameron/Eugene Island acquisition) and three
exploratory blocks from a private company for approximately $24,050,000.
Total estimated proved reserves acquired as a result of the West
Cameron/Eugene Island acquisition were 16.3 BCF of natural gas and 269,000
barrels of oil. Also in December 1993, the Company purchased interests in
the Loma Vieja Field in south Texas from another private company for
approximately $59,458,000. Total estimated proved reserves acquired as a
result of the Loma Vieja acquisition were 33.9 BCF of natural gas. In
addition, the Loma Vieja acquisition included 8 prospects with exploitation
or exploration potential, covering 2,332 net acres. The West Cameron/Eugene
Island and the Loma Vieja acquisitions were financed with proceeds of a
nonrecourse secured loan, internally generated funds, and funds obtained
under a bank credit facility. In other property acquisitions in 1993 Forest
acquired estimated proved reserves totaling 4.4 BCF of natural gas and
102,000 barrels of oil for an aggregate purchase price of $4,700,000.
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 such techniques 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
1
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. In total, the
Company undertook 39 workover and development projects in 1993 with the
following results:
Net Daily Production
Increases
----------------------------
Capital Natural Oil and
Number of Expenditures Gas Condensate
Area Projects (millions) (MCF) (BBLS)
---- --------- ----------- ------- ----------
Offshore 28 $8,865 31,097 1,192
Onshore 11 1,130 6,620 20
-- ------ ------ -----
Total 39 $9,995 37,717 1,212
-- ------ ------- ------
-- ------ ------- ------
Such results are not necessarily indicative of future results of the
Company's workover and development projects.
The Company participates in exploration activities primarily through farmout
arrangements. The Company's farmouts enable Forest to participate in its
exploration prospects without incurring additional exploration costs,
although with a reduced ownership in each prospect. During 1993, the Company
entered into farmout agreements covering 27 prospects, pursuant to which 14
wells were drilled resulting in 9 commercially productive properties. 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. During 1993, the Company sold properties with proved
reserves of approximately 1.2 BCF of natural gas and 281,000 barrels of oil
for net proceeds of $2,997,000.
The Company intends to pursue its acquisition and exploitation strategy while
continuing its efforts to improve its balance sheet, enhance its liquidity,
reduce the commodity price risk exposure of its investments in oil and gas
properties, reduce overhead on a per-unit basis of production and increase
operating efficiencies. 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 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. In February 1994, approximately 60% of the Company's natural gas was
committed to both interstate and intrastate natural gas pipeline companies,
primarily under volumetric production payment agreements and under long-term
contracts. The remainder of the Company'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.
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 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, 1993, approximately
85% of Forest's estimated proved reserves were attributable to natural gas on
an MCFE basis. During 1993, 82% of the Company's total production on an MCFE
basis consisted of natural gas. Approximately 54% of 1993 natural gas
production was sold in the spot market. In order to attempt to minimize the
price volatility to which the Company is subject, the Company, from time to
time,
2
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, 7 and 16 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 because any individual spot purchaser could be readily replaced by
another spot purchaser who would pay approximately the same sales price.
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 17 of Notes to Consolidated Financial
Statements.
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 both highly volatile and
generally dependent on world supply and demand. 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.
REGULATION
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
3
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
subject the Company to more restrictive pipeline imbalance tolerances and
greater penalties for violation of those tolerances. The FERC has issued
final orders of virtually all Order No. 636 pipeline restructuring
proceedings. Appeals of Order No. 636, as well as orders in the individual
pipeline restructuring proceedings, are currently pending and the Company
cannot predict the ultimate outcome of court review. This review may result
in the reversal, in whole or in part, of Order No. 636.
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 on the OCS. On
October 28, 1993, the FERC announced its intention to re-evaluate the
appropriateness of its traditional criteria for determining whether a
pipeline is a non-regulated gathering line in light of Order No. 636, and to
establish consistent policies for gathering rates and services for both
interstate pipelines and their affiliates. If the FERC were to apply Order
No. 509 to gatherers in the OCS, eliminate the exemption of gathering lines,
and redefine its jurisdiction over gathering lines, then these acts could
result in a reduction of available pipeline capacity for existing shippers in
the Gulf of Mexico, such as the Company.
In December 1992, the FERC issued Order No. 547, governing the issuance of
blanket marketer sales certificates to all natural gas sellers other than
interstate pipelines. The Order applies to non-first sales that remain
subject to the FERC's NGA jurisdiction. The FERC intends Order No. 547, in
tandem with Order No. 636, to foster a competitive market for natural gas by
giving natural gas purchasers access to multiple supply sources at market-
driven prices. Order No. 547 may increase competition in markets in which
the Company's natural gas is sold.
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
In August 1993, the Minerals Management Service (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 operators of oil and gas facilities
located on or adjacent to waters of the United States to establish $150
million in financial responsibility to cover oil spill related liabilities.
The Company cannot predict the final form of the rule that will be adopted,
but such a rule 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
4
and other affected regions. During recent meetings with the MMS, members of
the oil and gas, banking and insurance industries have commented on the
potential detrimental effect of OPA 90 if it is implemented as enacted. The
comment period of the formal rulemaking process has expired. There is no
estimate of when proposed rules will be published.
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 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.
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 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.
FOREIGN OPERATIONS
In 1992, the Company sold substantially all of its Canadian operations to
CanEagle Resources Corporation (CanEagle). Forest's investment in the
Canadian oil and gas industry is through its investment in and advances to
CanEagle. For further information concerning this transaction, see Note 3 of
Notes to Consolidated Financial Statements.
In Canada, the petroleum industry operates under federal, provincial and
municipal legislation and regulations governing taxes, land tenure,
royalties, production rates, pricing, environmental protection, exports and
other matters. Prices of oil and natural gas in Canada have been deregulated
and are determined by market conditions and negotiations between buyers and
sellers, although oil production volumes are regulated.
5
Various matters relating to the transportation and distribution of natural
gas are the subject of hearings before various regulatory tribunals. In
addition, although the price of natural gas exported from Canada is subject
to negotiation between buyers and sellers, the National Energy Board, which
regulates exports of natural gas, requires that natural gas export contracts
meet certain criteria as a condition of approving such contracts. These
criteria, including price considerations, are designed to demonstrate that
the export is in the Canadian public interest.
Several provincial governments have introduced a number of programs to
encourage and assist the oil and natural gas industry, including incentive
payments, royalty holidays and royalty tax credits.
Canadian governmental regulations may have a material effect on the economic
parameters for engaging in oil and gas activities in Canada and may have a
material effect on the advisability of investments in Canadian oil and gas
drilling activities.
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.
6
ITEM 2. PROPERTIES
Forest's principal properties are oil and gas properties located in the Gulf
of Mexico and in Texas, Oklahoma, and Wyoming.
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 19 of Notes to Consolidated Financial
Statements.
Since January 1, 1993, 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" date of such reserve estimates.
PRODUCTION
The following table shows net oil and natural gas production for Forest and
its wholly-owned subsidiaries for the three years ended December 31, 1993:
Net Oil and Natural Gas Production
--------------------------------------
1993 1992 1991
---- ---- ----
United States:
Natural Gas (MMCF) 41,114 27,814 22,517
Oil (MBBLS) 1,493 1,308 637
Canada:
Natural Gas (MMCF) - 1,360 1,360
Oil (MBBLS) - 142 210
Net production reported by CanEagle for its fiscal year ended September 30, 1993
was 2.1 BCF of natural gas and 281,000 barrels of oil. The Company's investment
in and advances to CanEagle are discussed in Note 3 of Notes to Consolidated
Financial Statements.
7
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 oil and condensate and the average production cost per
equivalent unit of production for the three years ended December 31, 1993 for
Forest and its wholly-owned subsidiaries:
United States Canada
-------------------- ---------------------
1993 1992 1991 1993 1992 1991
---- ---- ---- ---- ---- ----
Average Sales Prices:
Natural Gas
Production under long-term fixed
price contracts (MMCF) (1) 19,065 9,689 6,582 - - -
Average contract sales price
(per MCF) $ 1.47 1.43 2.38 - - -
Production sold on the
spot market (MMCF) 22,049 18,125 15,935 - 1,360 1,360
Spot sales price received
(per MCF) (2) (3) $ 2.36 1.96 1.68 - 1.12 1.19
Effects of energy swaps
(per MCF) (4) (.13) (.07) - - - -
--------- ------ ----- ----- ----- ------
Average spot sales price
(per MCF) (2) (3) $ 2.23 1.89 1.68 - 1.12 1.19
Total production (MMCF) 41,114 27,814 22,517 - 1,360 1,360
Average sales price
(per MCF) $ 1.88 1.73 1.89 - 1.12 1.19
Oil and Condensate
Production under long-term
contracts (MBBLS) (1) 300 201 152 - - -
Average contract sales
price (per BBL) $ 16.96 18.07 20.58 - - -
Production sold on the
spot market (MBBLS) 1,193 1,107 485 - 142 210
Spot sales price
received (per BBL) $ 16.27 18.48 24.08 - 17.61 19.77
Effects of energy swaps
(per BBL) (4) .71 (.26) 5.11 - - -
--------- ------ ----- ----- ----- ------
Average spot sales
price (per BBL) $ 16.98 18.22 29.19 - 17.61 19.77
Total production (MBBLS) 1,493 1,308 637 - 142 210
Average sales price
(per BBL) $ 16.97 18.19 25.74 - 17.61 19.77
Average production cost
(per MCFE) (5) (6) $ .39 .36 .41 - .61 .64
- --------------------------
(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.
(2) The 1992 amounts exclude $1.15 per MCF attributable to the settlement of
gas contract litigation with ONEOK, Inc. (the ONEOK settlement).
Including such amount, the sales price received and the average spot
sales price for natural gas were $3.11 and $3.04 per MCF, respectively.
(3) The 1991 amounts exclude $.07 per MCF attributable to a favorable ruling
with respect to royalties on take-or-pay settlements and $.06 per MCF
related to a favorable gas purchase contract settlement. Including such
amounts, the sales price received and the average sales price for
natural gas were both $1.77 per MCF.
(4) Energy swaps were entered into to hedge against price fluctuation.
(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. Such
production costs exclude all depreciation, depletion and amortization
associated with property and equipment.
(6) The 1992 amount excludes $.04 per MCF equivalent attributable to the
ONEOK settlement. Including such amount, the average production cost
per unit of production was $.40 per MCF equivalent.
Average sales prices received by CanEagle for its fiscal year ended September
30, 1993 were $1.77 CDN per MCF of natural gas and $20.77 CDN per barrel of
oil. CanEagle's natural gas production was sold under long-term contracts
and its oil production was sold on the spot market. The average production
cost per MCFE reported by CanEagle was $.49 CDN per MCFE. The Company's
investment in and advances to CanEagle are discussed in Note 3 of Notes to
Consolidated Financial Statements.
8
PRODUCTIVE WELLS
The following summarizes total gross and net productive wells of the Company
and its wholly-owned subsidiaries at December 31, 1993, all of which are in
the United States:
Productive Wells (A)
--------------------------------
Gross (B) Net (C)
--------- -------
Oil 190 127.8
Gas 403 123.9
----- -----
Totals (D) 593 251.7
----- -----
----- -----
(A) Productive wells are producing wells and wells capable of production,
including wells that are shut-in.
(B) 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.
(C) 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.
(D) Includes 46 dual completions. Dual completions are counted as one well.
If one completion is an oil completion, the well is classified as an oil
well.
At September 30, 1993, CanEagle had 33 net productive oil wells and 32 net
productive gas wells. The Company's investment in and advances to CanEagle
are discussed in Note 3 of Notes to Consolidated Financial Statements.
DEVELOPED AND UNDEVELOPED ACREAGE
Forest and its wholly-owned subsidiaries held acreage as set forth below at
December 31, 1993 and 1992. A majority of the developed acreage is subject
to a mortgage lien securing either the Company's bank indebtedness or its
nonrecourse secured debt. 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 4, 5 and 7 of Notes
to Consolidated Financial Statements.
Developed Acreage (A) Undeveloped Acreage (B)
--------------------- -----------------------
Gross (C) Net (D) Gross (C) Net (D)
--------- ------- --------- -------
Louisiana Offshore 177,430 170,249 147,456 100,166
Oklahoma 49,959 18,521 24,217 4,098
Texas Onshore 112,927 44,473 47,735 32,038
Texas Offshore 64,822 39,838 82,462 68,603
Wyoming 7,410 3,901 22,930 18,322
Other 14,591 2,394 13,587 7,631
------- ------- -------- --------
Total acreage at
December 31, 1993 427,139 279,376 338,387 230,858
------- ------- -------- --------
------- ------- -------- --------
Total acreage at
December 31, 1992 381,423 145,808 518,722 316,486
------- ------- -------- --------
------- ------- -------- --------
(A) Developed acres are those acres which are spaced or assigned to
productive wells.
(B) 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.
(C) 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.
(D) 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.
9
During 1993, the Company's gross and net developed acreage increased
approximately 12% and 92%, respectively, primarily as a result of property
acquisitions. The Company's gross and net undeveloped acreage decreased 35%
and 27%, respectively, because the acquisitions made during the year were
more than offset by reductions in acreage as a result of reclassifications to
developed acreage, lease expirations and the Company's decision not to renew
certain leases which were located primarily offshore Louisiana and in Texas.
Approximately 13% of the Company's total net undeveloped acreage is under
leases that have terms expiring in 1994, if not held by production, and
another approximately 44% of net undeveloped acreage will expire in 1995 if
not also held by production.
At September 30, 1993, CanEagle held 31,705 gross developed acres, 8,179 net
developed acres, 95,847 gross undeveloped acres and 33,478 net undeveloped
acres. The Company's investment in and advances to CanEagle are discussed in
Note 3 of Notes to Consolidated Financial Statements.
DRILLING ACTIVITY
Forest and its wholly-owned subsidiaries owned interests in net exploratory
and net development wells for the three years ended December 31, 1993 as set
forth below. This information does not include wells drilled under farmout
agreements as discussed below.
United States Canada (A)
---------------------- ---------------------
1993 1992 1991 1993 1992 1991
---- ---- ---- ---- ---- ----
Net Exploratory Wells: (B)
Dry (C) 1.2 1.0 - - - -
Productive (D) .3 - 1.0 - - .1
--- --- --- ---- ---- ----
1.5 1.0 1.0 - - .1
--- --- --- ---- ---- ----
--- --- --- ---- ---- ----
Net Development Wells: (B)
Dry (C) - - - - - -
Productive (D) 3.0 1.6 .5 - .2 .6
--- --- --- ---- ---- ----
3.0 1.6 .5 - .2 .6
--- --- --- ---- ---- ----
--- --- --- ---- ---- ----
(A) The net development well drilled in Canada in 1992 was completed prior
to the September 30, 1992 sale of Canadian operations to CanEagle. This
well was included in properties sold.
(B) 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.
(C) 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.
(D) Productive wells are producing wells and wells capable of production,
including wells that are shut-in.
During its fiscal year ended September 30, 1993, CanEagle drilled 2.1 productive
net development wells in Canada. The Company's investment in and advances to
CanEagle are discussed in Note 3 of Notes to Consolidated Financial Statements.
FARMOUT AGREEMENTS
Forest entered into farmout agreements with respect to 27 exploration prospects
during 1993. Under these agreements, 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. Eleven of the farmouts cover onshore prospects and 16 cover prospects
located in the Gulf of Mexico.
10
Fourteen of the 27 farmout prospects were drilled during 1993, resulting in
nine productive properties. Forest retained overriding royalty interests
ranging from 2.083% to 12.5% before payout, increasing to interests ranging
from a 10% overriding royalty interest to a 40% net working interest after
payout. One additional well was drilled and commenced production in 1994; the
Company anticipates that the 12 remaining undrilled farmouts will be drilled
during 1994.
During 1993, the Company entered into an exploration agreement under which a
third party agreed to drill a minimum of six additional exploratory wells
offshore. The Company retained overriding royalty interests in these prospects
of between 8.33% and 12.5% with the option to convert to working interests
ranging from 25% to 33 1/3% after payout of the first well on each prospect.
Four of these six wells were drilled by the end of 1993, resulting in one
productive well. The remaining two wells are scheduled to be drilled in the
first half of 1994.
The Company intends to continue to seek farmouts of exploration prospects when
they can be arranged on terms that are believed to be favorable.
During its fiscal year ended September 30, 1993, CanEagle concluded two farmout
agreements under which two successful gas wells were drilled and completed. The
Company's investment in and advances to CanEagle are discussed in Note 3 of
Notes to Consolidated Financial Statements.
PRESENT ACTIVITIES
At December 31, 1993, Forest and its wholly owned subsidiaries had three
development wells that were in the process of being drilled. All three wells
were determined to be productive in January 1994 and are currently being
tested. There was one well being drilled under a farmout agreement at year-
end, which was subsequently completed as a producing well.
At September 30, 1993 CanEagle had one development well that was in the process
of being drilled. This well was determined to be a gas well and commenced
production in November 1993. The Company's investment in and advances to
CanEagle are discussed in Note 3 of Notes to Consolidated Financial Statements.
DELIVERY COMMITMENTS
At December 31, 1993 Forest and its wholly-owned subsidiaries were obligated
to deliver approximately 36.3 BCF of natural gas and 479,000 barrels of oil
under the terms of volumetric production payments. The delivery commitments
cover approximately 35% and 12% 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. For further information
concerning the Company's production payment agreements, see Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations and Note 7 of Notes to Consolidated Financial Statements.
11
ITEM 3. LEGAL PROCEEDINGS
The Company has two natural gas sales contracts with Columbia Gas Transmission
Corp. (Transmission), a subsidiary of Columbia Gas System (CGS). On July 31,
1991, CGS and Transmission filed Chapter 11 bankruptcy petitions with the United
States Bankruptcy Court for the District of Delaware. Both contracts have been
rejected pursuant to the bankruptcy proceedings. The Company has filed a proof
of claim in the bankruptcy proceeding consisting of a secured claim of
$1,600,000 based on Louisiana vendor lien laws and an unsecured claim relating
to the rejection of the contracts. The secured claim arises from Transmission's
failure to pay the contract price for a period of time prior to rejection of the
contracts. The unsecured claim was calculated on an undiscounted basis and
without any assumption of mitigation of damages through spot market sales. No
prediction can be given as to when or how these matters will ultimately be
concluded.
The Company, in the ordinary course of business, is a party to various other
legal actions. In the opinion of management, none of these actions, including
those discussed above, will have a material adverse effect, either individually
or in the aggregate, on the financial condition of the Company.
12
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
ITEM 4A. EXECUTIVE OFFICERS OF FOREST
The following information with respect to the executive officers of Forest is
furnished pursuant to Instruction 3 to Item 401(b) of Regulation S-K.
YEARS WITH
NAME (A) AGE FOREST OFFICE (B)
-------- --- ---------- ----------
William L. Dorn* 45 22 Chairman of the Board and Chairman of
the Executive Committee since July
1991. Member of the Executive
Committee since August 1988.
President from February 1990 until
November 1993 and Chief Executive
Officer since February 1990.
Executive Vice President from August
1989 until February 1990, and prior
thereto Vice President. Member of
the Royalty Bonus Committee since
August 1991.
Robert S. Boswell* 44 5 President since November 1993. Vice
President from May 1991 until
November 1993 and Chief Financial
Officer since May 1991. Financial
Vice President from September 1989
until May 1991. Member of the
Executive Committee since July 1991,
member of the Royalty Bonus
Committee since August 1991. Chief
Financial Officer of Bovaird Supply
Company, Inc., from January 1988
until September 1989.
Bulent A. Berilgen 45 9 Vice President of Operations since
December 1993. Prior thereto Vice
President - Engineering and
Development since January 1992.
Prior thereto Regional Reservoir
Engineer.
Kenton M. Scroggs 41 11 Vice President since December 1993 and
Treasurer since May 1988. Prior
thereto Assistant Treasurer. Member
of the Administrative Committee of
the Company's Retirement Savings
Plan and Chairman of the Board of
Trustees of the Company's Pension
Trust.
13
YEARS WITH
NAME (A) AGE FOREST OFFICE (B)
-------- --- ---------- ----------
Forest D. Dorn 39 16 Vice President since February 1991 and
General Business Manager since
December 1993. Prior thereto General
Manager - Operations since January
1992. Prior thereto Assistant
Division Manager of the Southern
Division. Member of the
Contributions Committee.
David H. Keyte 37 6 Vice President and Chief Accounting
Officer since December 1993. Prior
thereto Corporate Controller since
January 1989. Prior thereto Manager
of Tax. Chairman of the
Administrative Committee of the
Company's Retirement Savings Plan
and member of the Board of Trustees
of the Company's Pension Trust.
Daniel L. McNamara 48 22 Secretary and Corporate Counsel since
January 1991. Prior thereto
Assistant Secretary and Associate
Corporate Counsel.
Joan C. Sonnen 40 4 Controller since December 1993. Prior
thereto Director of Financial
Accounting and Reporting since April
1991 and Manager of Financial
Systems and Reporting since July
1989. Prior thereto a principal with
Arthur Young & Company.
- -------------
*Also a Director
(A) William L. Dorn and Forest D. Dorn are brothers, and they are nephews of
John C. Dorn, a director of the Company.
(B) The term of office of each officer is one year from the date of his or her
election immediately following the last annual meeting of shareholders and
until the officer's respective successor has been elected and qualified or
until his or her earlier death, resignation or removal from office
whichever occurs first. Each of the named persons has held the office
indicated since the last annual meeting of shareholders, except as
otherwise indicated.
14
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Forest Oil Corporation has one class of common equity securities outstanding.
The Common Stock, par value $.10 per share, has one vote per share. During
1993, each share of the Class B Stock, par value $.10 per share, which had 10
votes per share, was reclassified into 1.1 shares of Common Stock pursuant to
a vote of the shareholders. In the event of dissolution, liquidation or
insolvency, holders of Common Stock share ratably in the net assets of Forest,
subject to the liquidation rights of the holders of the $.75 Convertible
Preferred Stock.
As of March 1, 1994, 27,942,755 shares of Common Stock were held by 2,109
recordholders and 1,244,715 Warrants were held by 88 recordholders.
The Company also has outstanding Warrants to purchase shares of its Common
Stock. Each Warrant entitles the holder to purchase one share of Common
Stock at a price of $3.00, is non-callable and expires on October 1, 1996.
Subject to the prior right of the holders of Forest's $.75 Convertible
Preferred Stock, the only restrictions on its present or future ability to
pay dividends are (i) the provisions of the New York Business Corporation Law
(NYBCL), (ii) certain restrictive provisions in the Indenture executed in
connection with Forest's 11 1/4% Senior Subordinated Notes due September 1,
2003 pursuant to which the Company is currently prohibited from paying any
cash dividends other than on its $.75 Convertible Preferred Stock, and (iii)
the Company's Credit Agreement dated December 1, 1993 with The Chase
Manhattan Bank (National Association), as agent, under which the Company is
restricted in amounts it may pay as dividends (other than dividends payable
in common stock). Under the dividend restriction in the Credit Agreement,
the Company currently has the ability to pay dividends in the approximate
amount of $1,920,000, assuming the cash dividend on the $.75 Preferred Stock
declared by the Company in February 1994 is paid in May 1994. There is no
assurance that Forest will pay any dividends. For further information on
Forest's ability to pay cash dividends on its Common Stock and $.75
Convertible Preferred Stock, see Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations and Notes 4, 6, 9 and 10 of
Notes to Consolidated Financial Statements.
The Company has one class of preferred stock outstanding. Annual dividends
on the $.75 Convertible Preferred Stock are cumulative and are payable
quarterly each February 1, May 1, August 1 and November 1, when and as
declared. 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.
Whenever dividends on the $.75 Convertible Preferred Stock have not been
paid, the amount of the deficiency, plus an amount equal to the accumulated
dividend for the then current quarterly dividend period, must be fully paid,
or declared and set apart for payment, before any dividend may be declared
and paid or set apart for payment upon the Common Stock, except for dividends
paid in shares of Common Stock.
Whenever $.75 Convertible Preferred Stock dividends are in arrears in an
amount equivalent to six full quarterly dividends, the holders of the $.75
Convertible Preferred Stock, voting separately as a class and with one vote
per share, will have the right to elect two directors. If two consecutive
dividend payments are in arrears, the holder of each share of $.75
Convertible Preferred Stock will be entitled to a penalty conversion right
enabling such holder to convert each such share, plus accumulated dividends,
into a share of Common Stock during a two-day period 30 days after the second
dividend payment date at a conversion price of 75% of the average of the last
reported sales prices of the Common Stock during the period from such second
dividend payment date to five trading days prior to the conversion date.
The holder of each share of $.75 Convertible Preferred Stock has the right to
convert each such share into 3.5 shares of Common Stock at any time. The
conversion rate is subject to adjustment in certain events.
15
The $.75 Convertible Preferred Stock may be redeemed at the option of the
Company, in whole or in part, upon notice duly given, at any time after the
earlier of (i) July 1, 1996, and (ii) the date on which the last reported
sales price of the Common Stock will have been $7.50 or higher for at least
20 of the prior 30 trading days, at the redemption prices set forth below, in
each case with an amount equal to dividends (whether or not declared) accrued
to the date fixed for redemption and remaining unpaid:
Redemption
Price Per
Redemption Period Share
---------------------------- ----------
July 1, 1993 to June 30, 1994 $10.50
July 1, 1994 to June 30, 1995 $10.33
July 1, 1995 to June 30, 1996 $10.17
July 1, 1996 and thereafter $10.00
As of March 1, 1994, 2,880,973 shares of $.75 Convertible Preferred Stock
were held by 86 recordholders.
Forest's Common Stock is traded on the National Market System of the National
Association of Securities Dealers, Inc., Automated Quotation System
(NASDAQ/NMS). The High and Low sales prices of the Common Stock for each
quarterly period of the years presented as reported by the NASDAQ/NMS are
listed in the chart below. The Class B Stock was not traded in any public
trading market. There were no dividends on Common Stock or Class B Stock in
1992, 1993 or in the first quarter of 1994.
High Low
------ -----
1992
-----
First Quarter $1-5/8 $1-3/16
Second Quarter 1-9/16 1-1/8
Third Quarter 3-1/4 1-3/8
Fourth Quarter 3-3/8 2-3/8
1993
----
First Quarter $4-1/2 $2-7/8
Second Quarter 5-13/16 4
Third Quarter 5-13/16 4-1/4
Fourth Quarter 5-7/16 3-5/16
1994
----
First Quarter
(through March 15) $4-3/4 $3-9/16
On March 15, 1994, the last reported sales price of the Common Stock as quoted
on the NASDAQ/NMS was $3-11/16 per share.
16
The Warrants are traded on the NASDAQ/NMS. The High and Low sales prices of
the Warrants for each quarterly period of the years presented as reported by
the NASDAQ/NMS are listed in the chart below.
High Low
---- ---
1992
----
First Quarter $ 1/2 $ 1/8
Second Quart 5/8 1/4
Third Quarter 1-3/4 15/32
Fourth Quarter 1-1/2 1
1993
----
First Quarter $2-3/8 $1-1/8
Second Quarter 3-5/8 2-1/16
Third Quarter 3-5/8 2-5/8
Fourth Quarter 3 1-3/4
1994
----
First Quarter
(through March 15) $2-3/4 $1-7/8
On March 15, 1994, the last reported sales price of the Warrants as quoted
on the NASDAQ/NMS was $1-7/8 per Warrant.
The $.75 Convertible Preferred Stock is traded on the NASDAQ/NMS. The High
and Low sales prices of the $.75 Convertible Preferred Stock for each
quarterly period of the years presented as reported by the NASDAQ/NMS are
listed in the chart below.
Stock
Dividends
High Low Paid (A)
---- --- ---------
1992
----
First Quarter $ 6-1/4 $ 4-1/4 0.092183
Second Quarter 5-3/4 4-1/4 0.175234
Third Quarter 11-1/4 5-1/4 0.153122
Fourth Quarter 12 8-3/4 0.071225
1993
----
First Quarter $15-3/4 $10-3/4 0.068587
Second Quarter 20-1/8 14-1/4 0.057176
Third Quarter 20-5/8 15-1/2 0.038513
Fourth Quarter 18-3/4 12 0.044563
1994
----
First Quarter
(through March 15) $17 $13-5/8 $ .1875
(A) In 1992 and 1993, the dividends on the $.75 Convertible Preferred Stock
were paid in shares of Common Stock at the above stated rates. On
February 1, 1994, a cash dividend of $.1875 was paid to holders of
record on January 14, 1994. On February 20, 1994 the Board of Directors
declared a cash dividend of $.1875 payable May 1, 1994 to holders of
record on April 8, 1994.
On March 15, 1994, the last reported sales price of the $.75 Convertible
Preferred Stock as quoted on the NASDAQ/NMS was $14-1/4 per share.
17
In October 1993, the Board of Directors adopted a shareholders' rights plan.
The Company issued a dividend of a preferred stock purchase right (the "Rights")
on each outstanding share of Common Stock of the Company, which, after the
Rights become exercisable, entitle the holder to purchase 1/100th of a share of
a newly issued series of the Company's preferred stock at a purchase price of
$30 per 1/100th of a preferred share, subject to adjustment. The Rights expire
on October 29, 2003 unless extended or redeemed earlier. The Rights will become
exercisable (unless previously redeemed or the expiration date of the Rights has
occurred) following a public announcement that a person or group (an "Acquiring
Person") has acquired 20% or more of the Common Stock or has commenced (or
announced an intention to make) a tender offer or exchange offer for 20% or more
of the Common Stock. In certain circumstances each holder of Rights (other than
an Acquiring Person) will have the right to receive, upon exercise, (i) shares
of Common Stock of the Company having a value significantly in excess of the
exercise price of the Rights, or (ii) shares of Common Stock of an acquiring
company having a value significantly in excess of the exercise price of the
Rights.
18
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
The following table sets forth selected data regarding the Company as of and for
each of the years in the five-year period ended December 31, 1993. This data
should be read in conjunction with Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations and the Consolidated Financial
Statements and Notes thereto.
YEARS ENDED DECEMBER 31,
------------------------------------------------
1993 1992 (1) 1991 1990 1989
---- ---- ---- ---- ----
(In Thousands Except per Share Amounts and Volumes)
FINANCIAL DATA
Revenue $ 105,148 113,186 69,897 84,824 131,555
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Earnings (loss) before cumulative effects of
changes in accounting principles and
extraordinary items (9,355) 7,298 (34,850) (75,549) (9,398)
Cumulative effects of changes in
accounting principles (1,123) - - - -
------- ------- ------- ------- -------
Earnings (loss) before extraordinary items (10,478) 7,298 (34,850) (75,549) (9,398)
Extraordinary items - extinguishment of debt (10,735) - 9,502 - -
------- ------- ------- ------- -------
Net earnings (loss) $ (21,213) 7,298 (25,348) (75,549) (9,398)
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Weighted average number of common shares
outstanding 21,997 13,774 12,494 12,307 11,498
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Net earnings (loss) attributable to
common stock $ (23,463) 4,950 (30,557) (85,395) (15,014)
------- ------ ------- ------- -------
------- ------ ------- ------- -------
Primary earnings (loss) per share: (2)
Earnings (loss) before cumulative effects of
changes in accounting principles and
extraordinary items $ (.53) .36 (3.21) (6.94) (1.31)
Cumulative effects of changes in accounting
principles (.05) - - - -
------- ------- ------- ------- -------
Loss before extraordinary items (.58) .36 (3.21) (6.94) (1.31)
Extraordinary items - extinguishment of debt (.49) - .76 - -
------- ------- ------- ------- -------
Net earnings (loss) attributable to common
stock $ (1.07) .36 (2.45) (6.94) (1.31)
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Total assets $ 426,755 378,532 296,189 339,676 470,061
Long-term obligations
and redeemable preferred stock 288,588 250,672 203,136 220,508 257,672
Shareholders' equity 88,156 59,881 54,840 58,457 88,689
OPERATING DATA
Annual production:
Gas (MMCF) 41,114 29,174 23,877 31,415 36,530
Oil (MBBLS) 1,493 1,450 847 912 552
Average price received:
Gas (per MCF) $ 1.88 1.70 1.84 2.06 2.25
Oil (per Barrel) 16.97 18.14 25.31 23.19 17.94
Capital expenditures:
Property acquisitions $ 144,916 88,772 13,560 5,401 10,032
Exploration 5,433 2,297 9,723 33,067 31,497
Development 20,472 15,558 12,381 26,998 42,676
------- ------- ------- ------- -------
$ 170,821 106,627 35,664 65,466 84,205
------- ------- ------- ------- -------
------- ------- ------- ------- -------
Overhead Costs $ 19,561 18,760 23,292 41,176 38,193
Proved Reserves:
Gas (MMCF) 273,382 194,655 193,471 205,013 272,904
Oil (MBBLS) 8,198 7,560 5,315 6,559 9,262
Standardized measure of discounted future
net cash flows relating to proved oil
and gas reserves $ 299,053 227,009 188,069 241,303 326,126
(1) The results for 1992 include the effects of the ONEOK settlement.
(2) 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 $.29.
19
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 Company's net loss was $21,213,000 in 1993 compared to
net earnings of $7,298,000 in 1992 and a net loss of $25,348,000 in 1991. There
would have been a net loss of $16,745,000 in 1992 excluding the effects of the
settlement of gas contract litigation with ONEOK Inc. (the ONEOK settlement).
Total revenue less operating expenses (consisting of oil and gas production
expense and expensed general and administrative costs) increased in 1993
compared to the 1992 results (excluding the effects of the ONEOK settlement) as
a result of the acquisition of properties; however, this increase was more than
offset by higher depreciation and depletion expense, an extraordinary loss of
$10,735,000 (net of tax benefit of $4,652,000) recorded as a result of the
redemption or purchase of all of the Company's 12 3/4% Senior Secured Notes and
long-term subordinated debt and a charge of $1,123,000 to reflect the effects of
cumulative changes in accounting principles related to postretirement benefits
and income taxes. The 1992 results improved significantly compared to 1991 due
to approximately $24,043,000 of net earnings associated with the ONEOK
settlement in December 1992 and because there was no writedown of the carrying
value of the Company's oil and gas properties required in 1992 by SEC
regulations. The 1991 loss included a writedown of the Company's oil and gas
properties of $22,400,000 on an after-tax basis, offset by an extraordinary gain
of $9,502,000 (net of income taxes of $4,895,000) on extinguishment of debt.
The ONEOK settlement in 1992 had a significant impact on the Company's reported
revenue, expense and net earnings. A summary of the Company's income and
expenses for 1992, before and after the amounts recorded as a result of the
ONEOK settlement, is as follows:
Year ended
Effects of December 31, 1992
Year ended ONEOK excluding ONEOK
December 31, 1992 settlement settlement
----------------- ---------- -----------------
(In Thousands)
REVENUE:
Oil and gas sales $ 99,239 22,392 76,847
Miscellaneous, net 13,947 15,149 (1,202)
------- ------ -------
Total revenue 113,186 37,541 75,645
EXPENSES:
Oil and gas production 15,865 1,589 14,276
General and administrative 11,611 (477) 12,088
Interest 27,800 - 27,800
Depreciation and depletion 46,624 - 46,624
------- ------ -------
Total expenses 101,900 1,112 100,788
------- ------ -------
Earnings (loss) before
income taxes 11,286 36,429 (25,143)
Income tax expense
Current 435 - 435
Deferred expense (benefit) 3,553 12,386 (8,833)
------- ------ -------
3,988 12,386 (8,398)
------- ------ -------
Net earnings $ 7,298 24,043 (16,745)
------- ------ -------
------- ------ -------
20
The inclusion of the effects of the ONEOK settlement in a discussion of the
Company's results of operations distorts the trends which would otherwise be
reported. In the discussion which follows, results for 1992 exclude the effects
of the ONEOK settlement in order to more meaningfully compare and discuss the
Company's results of operations for 1993, 1992 and 1991.
REVENUE. Total revenue increased 39% to $105,148,000 in 1993 from $75,645,000
in 1992, primarily due to increased production from newly-acquired properties.
Total revenue increased by 8% to $75,645,000 in 1992 from $69,897,000 in 1991.
The increase is due primarily to increased production volumes, despite a
decrease in average sales prices for both oil and natural gas.
Oil and gas sales increased to $102,883,000 from $76,847,000, or by
approximately 34% in 1993 from 1992, primarily due to increased production from
newly-acquired properties and an 11% increase in the average sales price for
natural gas. In 1993, oil production volumes were up 3% and natural gas
production volumes were up 41% compared to 1992. The increase in revenue
attributable to the increased production was partially offset by a 6% decrease
in the average sales price for oil.
Oil and gas sales increased to $76,847,000 from $68,876,000 or by approximately
12% in 1992 from 1991. The increase primarily resulted from increased
production volumes, despite a decrease in average sales prices for both oil and
natural gas. In 1992, oil production volumes were up 71% and natural gas
production volumes were up 22% compared to 1991. The increased volumes were
primarily the result of property acquisitions in 1992. The increase in revenue
attributable to the increased production was partially offset by a 28% decrease
in the average sales price for oil and an 8% decrease in the average sales price
for natural gas.
21
The production volumes and average sales prices for the three years ended
December 31, 1993 for Forest and its wholly-owned subsidiaries were as follows:
Years Ended December 31,
-----------------------------
1993 1992 1991
------- ------ ------
Natural Gas
-----------
Production under long-term fixed price
contracts (MMCF)(1) 19,065 9,689 6,582
Average contract sales price (per MCF) $ 1.47 1.43 2.38
Production sold on the spot market (MMCF) 22,049 19,485 17,295
Spot sales price received (per MCF)(2)(3) $ 2.36 1.90 1.64
Effects of energy swaps (per MCF)(4) (.13) (.07) -
------ ------ ------
Average spot sales price (per MCF)(2)(3) $ 2.23 1.83 1.64
Total production (MMCF) 41,114 29,174 23,877
Average sales price (per MCF) $ 1.88 1.70 1.84
Oil and Condensate
------------------
Production under long-term
fixed price contracts (MBBLS)(1) 300 201 152
Average contract sales price (per BBL) $ 16.96 18.07 20.58
Production sold on the spot market (MBBLS) 1,193 1,249 695
Spot sales price received (per BBL) $ 16.27 18.41 21.24
Effects of energy swaps (per BBL)(4) .71 (.26) 5.11
------ ------ ------
Average spot sales price (per BBL) $ 16.98 18.15 26.35
Total production (MBBLS) 1,493 1,450 847
Average sales price (per BBL) $ 16.97 18.14 25.31
- ------------------
(1) Production under long-term fixed price contracts includes volumes delivered
under volumetric production payments, net of royalties. For further
information concerning volumes and prices recorded under volumetric
production payments, see "Volumetric Production Payments."
(2) The 1992 amounts exclude $1.15 per MCF attributable to the ONEOK
settlement. Including such amount, the sales price received and the
average spot sales price for natural gas were $3.05 and $2.98 per MCF,
respectively.
(3) The 1991 amounts exclude $.07 per MCF attributable to a favorable ruling
with respect to royalties on take-or-pay settlements and $.06 per MCF
related to a favorable gas purchase contract settlement. Including such
amounts, the sales price received and the average sales price for natural
gas were both $1.77 per MCF.
(4) Energy swaps were entered into to hedge the price of spot market volumes
against price fluctuation.
22
Natural gas sold pursuant to volumetric production payment agreements and other
long-term fixed price contracts represented approximately 46% of production in
1993 versus 33% in 1992 and 28% in 1991. In recent years, the industry trend
has been for more natural gas to be sold on the spot market as long-term
contracts expire. The increase experienced by Forest in natural gas sold under
long-term fixed price contracts in 1993, 1992 and 1991 was the result of the
Company entering into volumetric production payment agreements.
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. The
net expense of $1,202,000 in 1992 was primarily attributable to a $926,000
provision for future rent payments on vacated office space. The 1991 amount of
$1,021,000 included interest income of $1,314,000 on cash balances invested in
short-term investments and $2,032,000 of revenue associated with a favorable
ruling by a Texas court with respect to severance tax on take-or-pay
settlements, offset by $1,550,000 provided for uncollectible receivables and
$850,000 of refund claims which were abandoned.
OIL AND GAS PRODUCTION EXPENSE. Oil and gas production expense increased 37% to
$19,540,000 in 1993 compared to $14,276,000 in 1992 due primarily to increased
production from newly acquired properties and increased workover expense. Oil
and gas production expense increased 14% to $14,276,000 in 1992 compared to
$12,548,000 in 1991 due to increased production. In 1993, production expense
was approximately $.39 on an MCFE basis, compared to $.38 in 1992 and $.43 in
1991. The decrease in 1992 compared to 1991 was the result of cost-savings
measures coupled with economies of scale achieved when certain fixed operating
costs were spread over a larger asset base.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense for 1993
was $12,003,000 compared to $12,088,000 in 1992. Increases attributable to
severance and employee relocation costs and the effects of the postretirement
medical benefit accrual in 1993 were more than offset by lower office and
storage rentals and lower professional services expense. General and
administrative expense for 1992 increased 27% to $12,088,000 from $9,541,000 in
1991, reflecting a decrease in the capitalization rate applied to total overhead
costs. The decrease in the capitalization rate was the result of a decrease in
the percentage of employees' time spent working directly on exploration and
development projects. The capitalization rate remained relatively constant from
1992 to 1993.
The Company has devoted significant effort to reducing total overhead costs.
Total overhead costs, including amounts related to exploration and development
activities, were $19,561,000 in 1993, $19,237,000 in 1992 and $23,292,000 in
1991. The increase in 1993 from 1992 was only 2% despite charges amounting to
$2,300,000 for severance and employee relocation costs and $480,000 for
postretirement medical benefits; without these charges, total overhead costs
would have decreased by approximately 13% in 1993 compared to 1992. 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 an employee's former residence in accordance with the Company's relocation
policy. The decrease in total overhead costs in 1992 from 1991 was primarily
due to reductions in workforce which occurred during 1991. The following table
summarizes the total overhead costs incurred during the periods, including
retirement benefits for executives and directors:
Years Ended December 31,
-----------------------------
1993 1992 1991
------- ------ ------
(In Thousands)
Overhead costs capitalized $ 7,558 7,149 12,801
General and administrative costs expensed 12,003 12,088 10,491(A)
------- ------ ------
Total overhead costs $19,561(B) 19,237 23,292
------- ------ ------
------- ------ ------
(A) Includes $950,000 in 1991 for retirement benefits for executives and
directors.
(B) Includes approximately $2,300,000 of severance and employee relocation
costs and $480,000 for postretirement medical benefits.
23
RETIREMENT BENEFITS FOR EXECUTIVES AND DIRECTORS. In December 1990, the Company
entered into retirement agreements with seven executives and directors
("Retirees") pursuant to which the Retirees will receive supplemental retirement
payments totalling approximately $1,127,700 per year through 1996, $1,087,400 in
1997, $938,400 in 1998 and approximately $740,400 per year in 1999 and 2000.
The liability to the Retirees was recorded in 1990. Additional expense of
$950,000 was recorded in 1991 to reflect the accrual of amounts due to certain
Retirees upon resignation as directors of the Company.
RESTRUCTURING. Restructuring expense in 1991 includes the costs of the
Company's implementation of a reorganization and consolidation plan. Costs
recorded in 1991 of approximately $3,585,000 related to reductions in workforce
and a consolidation of the Company's technical staff, reduced by a credit
recognized upon curtailment of the Company's defined benefit pension plan.
INTEREST EXPENSE. Interest expense of $23,729,000 in 1993 decreased $4,071,000
or 15% compared to 1992, primarily due to redemptions or purchases of certain of
the Company's subordinated debentures and 12 3/4% Senior Secured Notes in 1993,
partially offset by the interest expense incurred in connection with the
Company's new 11 1/4% Senior Subordinated Notes. Interest expense of
$27,800,000 in 1992 increased $4,494,000 or 19% compared to 1991 due to
increased indebtedness in the form of a dollar-denominated production payment
related to the acquisition of properties.
DEPRECIATION AND DEPLETION EXPENSE. Depreciation and depletion expense
increased 30% to $60,581,000 in 1993 from $46,624,000 in 1992 due to increased
production in the 1993 period as a result of property acquisitions and
workovers. Depreciation and depletion expense increased 22% to $46,624,000 in
1992 from $38,229,000 in 1991 due to increased production volumes despite a
slightly lower rate per MCFE. The depletion rate was $1.19 per MCFE for U.S.
production in 1993 compared to corresponding rates of $1.21 for U.S. production
and $1.19 for Canadian production in 1992 and $1.28 for U.S. production and
$1.37 for Canadian production in 1991.
IMPAIRMENT OF OIL AND GAS PROPERTIES. The Company recorded a writedown of its
oil and gas properties of $34,000,000 in 1991 due to the poor results of the
Company's 1990 exploration program and depressed natural gas prices.
Additional writedowns of the full cost pools may be required if prices 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 additional reserves, if any.
The average spot market price received by the Company for Gulf Coast natural gas
production was approximately $2.48 per MCF at December 31, 1993. The West Texas
Intermediate price for crude oil received by the Company was $12.00 per barrel
at December 31, 1993. The average Gulf Coast spot price received by the Company
for natural gas declined from $2.48 per MCF at December 31, 1993 to $2.46 per
MCF at March 1, 1994. The West Texas Intermediate price for crude oil increased
from $12.00 per barrel at December 31, 1993 to $13.00 per barrel at March 1,
1994.
INVESTMENT IN AND ADVANCES TO AFFILIATE. In May 1992, the Company transferred
substantially all of its Canadian oil and gas properties to a wholly-owned
Canadian subsidiary, Forest Canada I Development Ltd. (FCID). On September 30,
1992 FCID sold its Canadian assets and related operations to CanEagle for
approximately $51,250,000 in Canadian funds ($41,000,000 U.S.). An independent
third party financed the purchase by CanEagle. In the transaction, FCID
received cash of approximately $28,000,000 CDN ($22,400,000 U.S.), net of
expenses, and provided financing to the third party in the aggregate principal
amount of $22,000,000 CDN ($17,600,000 U.S.).
CanEagle's capital was restructured in 1993. At December 31, 1993, the
Company's ownership interest in CanEagle consisted of 15,400,000 shares of Class
A Preferred Shares and 1,400,000 shares of Class B Preferred Shares of CanEagle
and a $6,000,000 CDN subordinated debenture.
24
Substantial uncertainty exists regarding whether CanEagle is a going concern due
to a required principal payment of $16,300,000 on its Senior Debenture due June
30, 1994. CanEagle is in the process of refinancing the Senior Debenture with
its lender, but there is no assurance that such refinancing can be completed on
mutually acceptable terms prior to the due date.
No gain was recognized as a result of the CanEagle transaction because
collection of the remaining sales price was not reasonably assured. Due to its
continuing financial interest in CanEagle, the Company is accounting for its
investment in CanEagle under the equity method. Accordingly, losses will be
recognized to the extent that such losses exceed (a) amounts attributable to
securities subordinate to the Company's interest, and (b) a basis difference of
$780,000 CDN attributable to the 1993 capital restructuring of CanEagle. Under
this method, no portion of the CanEagle loss was required to be recorded by the
Company in 1993.
Earnings related to the Company's interest in CanEagle will be recognized only
if realization is assured. Accordingly, amounts received as interest on the
subordinated note during 1993 (approximately $540,000 CDN) were recorded as a
reduction of the Company's investment in and advances to CanEagle. There were
no dividends received in 1993.
The excess of the carrying value of properties sold over the cash received, or
approximately $16,451,000 U.S. at December 31, 1993, represents Forest's
investment in CanEagle.
CHANGES IN ACCOUNTING
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
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
$480,000 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 and, as such, prior periods have not been restated.
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.
CAPITAL RESOURCES AND LIQUIDITY
CASH FLOW. Historically, one of the Company's primary sources of capital has
been net cash provided by operating activities, which has varied dramatically in
the last three years. The majority of the increases and decreases in net cash
provided by operating activities is attributable to increases and decreases in
oil and gas revenue. While expenses associated with operations have been
relatively stable, revenue from operations has varied dramatically each year
depending upon factors such as natural gas contract settlements and price
fluctuations, which are difficult to predict.
25
The following summary table reflects comparative cash flows for the Company for
the periods ended December 31, 1993, 1992 and 1991:
Years Ended December 31,
1993 1992 1991
------- ------ ------
(In Thousands)
Funds provided by operations (A)(B) $ 52,667 24,433(C) 19,331
Net cash provided by operating activities (B) 41,560 19,124(D) 15,570
Net cash used by investing activities (170,134) (83,354) (21,546)
Net cash provided by financing activities 72,048 57,713 17,919
(A) Funds provided by operations is equal to net cash provided by operating
activities adjusted for the change in working capital items.
(B) Includes approximately $32,702,000, $14,081,000 and $8,979,000 of revenue
recognized by the amortization of the Company's volumetric production
payments for the years ended December 31, 1993, 1992 and 1991,
respectively.
(C) Excludes $36,429,000 of net proceeds associated with the ONEOK settlement.
(D) Excludes $51,250,000 of revenue associated with the ONEOK settlement in
1992.
SHORT-TERM LIQUIDITY AND WORKING CAPITAL DEFICIT. In December 1993, the Company
entered into a secured master credit facility (the Credit Facility) with The
Chase Manhattan Bank, NA. (Chase) as agent for a group of banks. Under the
Credit Facility, the Company may borrow up to $17,500,000 for acquisition or
development of proved oil and gas reserves, which amount is subject to semi-
annual redetermination, and up to $17,500,000 for working capital and general
corporate purposes. 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, and a negative pledge
on remaining assets. Borrowings under the Credit Facility bear interest at the
Chase base rate plus 3/8 of 1% or 1,2,3 or 6 month LIBOR plus 1 and 5/8%,
payable quarterly. A commitment fee of 1/2 of 1% is charged on unused
availability. The maturity date of the Credit Facility is December 31, 1996.
Under the terms of the Credit Facility, the Company is subject to certain
covenants, including restrictions or requirements with respect to working
capital, net cash flow, additional debt, asset sales, mergers, cash dividends on
capital stock and reporting responsibilities. At December 31, 1993 the
outstanding balance under this facility was $25,000,000.
Due to the significant capital requirements of acquisition and development
activities undertaken in December 1993, the Company reported a working capital
deficit of $14,496,000 at December 31, 1993. The Company did not meet the test
imposed by the working capital covenant of the Credit Facility; compliance with
this covenant was waived by Chase at December 31, 1993. The deficit was funded
in the first quarter of 1994 primarily by additional borrowings of $9,000,000
under the Credit Facility, net proceeds of $2,600,000 from the sale of non-
strategic oil and gas properties, and a short-term loan from The Chase Manhattan
Bank, N.A. of $4,000,000 secured by a pledge of the Company's CanEagle
securities. These cash inflows, in addition to cash provided by operating
activities, enabled the Company to meet its obligations with respect to
principal and interest payments and other short-term obligations. The Company
currently has no additional borrowing capacity under the Credit Facility.
The Company continues to explore additional sources of short-term liquidity to
fund its working capital deficits, including an increase in the Credit Facility,
sale of additional non-strategic properties and excess equipment, monetization
of its investment in and advances to CanEagle and other measures. Expected
increases in operating
26
cash flows from recent property acquisitions are also expected to improve the
Company's short-term liquidity, although there can be no assurance that this
will be the case due to uncertainties in the markets for oil and natural gas and
the unpredictability inherent in oil and gas operations.
LONG-TERM LIQUIDITY. Since 1991, the Company has taken several significant
steps to improve its long-term liquidity. In 1991, the Company consummated its
recapitalization pursuant to which the Company's outstanding debt and preferred
stock were restructured in order to reduce its fixed financial costs. The
Company also undertook certain actions in 1991 to implement its operating
strategy, to control and reduce its operating costs, and to improve its
operating efficiency. The Company continues to devote significant efforts in
these areas.
On December 24, 1992, the Company received gross proceeds of $51,250,000 as a
result of the ONEOK settlement. The net proceeds, after payment of related
royalties and production taxes, were approximately $36,429,000. Pursuant to the
terms of its 12 3/4% Senior Secured Notes, the Company was required to make an
offer to purchase $16,000,000 principal amount of the 12 3/4% Senior Secured
Notes at a purchase price of 100% of their principal amount plus accrued
interest to the date of purchase. Pursuant to such offer, the Company purchased
approximately $3,926,000 principal amount of 12 3/4% Senior Secured Notes in
February, 1993. The remainder of the net proceeds were used for general
corporate purposes, including working capital, debt reduction and the
acquisition of oil and gas properties.
On June 15, 1993, the Company issued 11,080,000 shares of Common Stock for $5.00
per share in a public offering. The net proceeds from the issuance of the
shares totalled approximately $51,506,000 after issuance costs and underwriting
fees, of which the Company used approximately $30,300,000 to purchase or redeem
12 3/4% Senior Secured Notes. The remainder of the net proceeds was used for
general corporate purposes, including working capital, debt reduction and the
acquisition of oil and gas properties.
On September 8, 1993, the Company completed a public offering of $100,000,000
aggregate principal amount of 11-1/4% Senior Subordinated Notes due September 1,
2003. The 11 1/4% Senior Subordinated Notes were issued at a price of 99.259%
yielding 11.375% to the holders. On October 13, 1993 the Company used the net
proceeds from the sale of the 11 1/4% Senior Subordinated Notes of approximately
$95,827,000, together with approximately $19,400,000 of available cash, to
redeem all of its outstanding 12 3/4% Senior Secured Notes and long-term
subordinated debentures.
On November 9, 1993, the Company purchased $308,000 principal amount of its 5
1/2% Convertible Subordinated Debentures. The remaining $7,171,000 principal
amount of the 5 1/2% Debentures was redeemed February 1, 1994.
On December 30, 1993, the Company entered into a nonrecourse secured loan
agreement (the Enron loan) arranged by Enron Finance Corp., an affiliate of
Enron Gas Services. For a further discussion of the Enron loan, see
"Nonrecourse Secured Loan and Dollar-Denominated Production Payment" below.
This financing provided acquisition capital, and capital to execute Forest's
exploitation strategy.
Many of the factors which may affect the Company's future operating performance
and long-term liquidity are beyond the Company's control, including, but not
limited to, oil and natural gas prices, governmental actions and taxes, the
availability and attractiveness of properties for acquisition, the adequacy and
attractiveness of financing and operational results.
VOLUMETRIC PRODUCTION PAYMENTS. Through December 31, 1993, the Company received
approximately $134,705,000 (net of fees) from the sale of volumetric production
payments and, in return, committed to deliver from the subject properties
approximately 77.4 BCF of natural gas and 770,000 barrels of oil to entities
associated with Enron Corp. (Enron). As of December 31, 1993, the volumes
remaining to be delivered were approximately 36.3 BCF of natural gas and 479,000
barrels of oil. 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.
27
The purchaser of a volumetric production payment determines the amount paid to
the Company for the production payment by calculating the net present value of
the scheduled deliveries priced using the purchaser's assumed future prices.
However, the sales price per MCFE recorded by the Company upon delivery of
production payment volumes is determined by dividing the net proceeds from the
sale of the production payment by the total volumes scheduled to be delivered.
This price is therefore fixed at the inception of the production payment and
does not change. There is no interest expense recorded with respect to a
volumetric production payment, the interest factor having been effectively
netted against the calculated sales price. In addition, the Company must pay
applicable royalties on volumes delivered and is responsible for production-
related costs associated with operating the properties subject to the production
payment agreements. These accounting treatments should be considered when
assessing the Company's financial statements and related information, including
information presented with respect to cash flows and average prices for volumes
sold under fixed contracts.
Deferred revenue relating to production payments was $67,228,000 as of December
31, 1993. The annual amortization of deferred revenue and the corresponding
delivery and net sales volumes are set forth below:
Net sales volumes
Volumes required to be attributable to production
delivered to Enron payment deliveries (1)
---------------------- --------------------------
Natural Natural
Annual amortization Oil Gas Oil Gas
of deferred revenue (MBBLS) (MMCF) (MBBLS) (MMCF)
------------------- ------- ------- ------- --------
1994 $34,935 218 19,422 182 15,672
1995 19,797 174 10,425 146 8,412
1996 7,278 87 3,534 73 2,852
1997 2,390 - 1,361 - 1,098
Thereafter 2,828 - 1,551 - 1,252
------- --- ------ --- ------
$67,228 479 36,293 401 29,286
------- --- ------ --- ------
------- --- ------ --- ------
(1) Represents volumes required to be delivered to Enron net of estimated
royalty volumes.
NONRECOURSE SECURED LOAN AND DOLLAR-DENOMINATED PRODUCTION PAYMENT. Under the
terms of the Enron loan agreement and a dollar-denominated production payment
sold in February 1992 in connection with the acquisition of the Harbert Energy
Corporation properties, the Company is required to make payments based on the
net proceeds, as defined, from certain subject properties.
As of December 31, 1993, the Enron loan of $57,400,000, which bears annual
interest at the rate of 12.5%, was recorded at $53,101,000 to reflect the
conveyance to the lender of a 20% interest in the net profits, as defined, of
the Loma Vieja properties. Under the terms of the Enron loan, additional funds
may be advanced to fund a portion of the development projects which will be
undertaken by the Company on the properties pledged as security for the loan.
Payments of principal and interest under the Enron 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. The Company's current
estimate is that 1994 payments will reduce the recorded liability by
approximately $983,000. Payments, if any, under the net profits conveyance will
commence upon repayment of the principal amount of the Enron loan and will cease
when the lender has received an internal rate of return, as defined, of 18%
(15.25% through December 31, 1995). Properties to which approximately 22% of
the Company's estimated proved reserves are attributable, on an MCFE equivalent
basis, are dedicated to repayment of the Enron loan.
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. At December 31, 1993 the remaining
recorded liability was $21,305,000. Under the terms of the dollar-denominated
production payment, the Company must make a monthly cash payment which is the
greater of a base amount or 85% of the 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's
current estimate is that 1994 payments will
28
reduce the recorded liability by approximately $3,388,000. Properties to which
approximately 7% of the Company's estimated proved reserves are attributable, on
an MCFE basis, are dedicated to this production payment financing through July
1999.
HEDGING PROGRAM. In addition to the volumes of natural gas and oil dedicated to
volumetric production payments, the Company has also used 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, 1993 the Company had
natural gas swaps for an aggregate of approximately 30 MMBTU per day of natural
gas during 1994 at fixed prices ranging from $1.90 to $2.30 per MMBTU. At
December 31, 1993 the Company had no oil swaps in place.
OPTION AGREEMENT. Under another agreement (the Option Agreement), the Company
paid a premium of $516,000 in conjunction with the closing of the Enron loan
agreement. The payment of this premium gives Forest the right to set a floor
price of $1.70 per MMBTU on a total of 18.4 BBTU of natural gas over a five year
period commencing January 1, 1995. In order to exercise this right to set a
floor, the Company must pay an additional premium of 10 CENTS per MMBTU,
effectively setting the floor at $1.60 per MMBTU. The premium of $516,000
related to the Option Agreement was recorded as a long-term asset and will be
amortized as a reduction to oil and gas income beginning in 1995 based on the
volumes involved.
TRIGGER AGREEMENTS. Two trigger agreements were entered into during 1993.
Under a "trigger" agreement, the Company agrees to enter into a swap agreement
at a later date based upon a specified margin over an agreed-upon third party
index. One agreement originally entered into in July 1993 obligated the Company
to enter into a gas swap arrangement in 1994. This agreement was terminated in
December 1993, in exchange for which the Company will pay $0.2675 per MMBTU on
5,000 MMBTU per day for each contract month, which equates to $488,000. The
discounted value of this amount, or $457,000, has been recorded as expense and
as a liability at December 31, 1993 and will be paid in monthly installments of
approximately $41,000 during 1994. The second trigger agreement was converted
into a natural gas swap and is included in the natural gas swaps discussed
above. The Company currently has no open trigger agreements.
SUMMARY OF CASH FLOW CONSIDERATIONS AND EXPOSURE TO PRICE AND RESERVE RISK.
Pursuant to certain of the Company's financing arrangements, significant amounts
of production are contractually dedicated to production payments and the
repayment of nonrecourse debt over the next five years (dedicated volumes). The
dedicated volumes decrease over the next five years and also decrease as a
percentage of the Company's total production during this period. The production
volumes not contractually dedicated to repayment of nonrecourse debt
(undedicated volumes) are relatively stable but increase as a percentage of the
Company's total production over the next five years. This relative stability of
undedicated volumes is due to the fact that the decrease in dedicated volumes
corresponds generally to the Company's estimates of the decrease in its total
production. In the Company's opinion, the relative stability of undedicated
volumes should provide a more constant level of cash flow available for
corporate purposes other than debt repayment. The following table presents, on
a percentage basis, the Company's estimates of dedicated and undedicated volumes
as a percentage of estimated total production:
1994 1995 1996 1997 1998 Thereafter Total
---- ---- ---- ---- ---- ---------- -----
Dedicated volumes 60% 58% 41% 40% 30% 9% 36%
Undedicated volumes 40 42 59 60 70 91 64
--- --- --- --- --- --- ---
Total production 100% 100% 100% 100% 100% 100% 100%
--- --- --- --- --- --- ---
--- --- --- --- --- --- ---
As a result of volumetric production payments, energy swaps, and fixed
contracts, the Company currently estimates that approximately 62% of its natural
gas production and 15% of its oil production will not be subject to price
fluctuations from January 1994 through December 1994. Existing hedge agreements
currently cover approximately 42% of the Company's natural gas production and
12% of its oil production for the year ending
29
December 31, 1995. Currently, it is the Company's intention to commit no more
than 75% of its production to such arrangements at any point in time. See
"Hedging Program" below.
The Company's hedging strategy for dedicated volumes differs from that for
undedicated volumes. The Company believes that hedging of dedicated volumes
provides for greater assurance of debt repayment and decreased financial risk.
The Company believes that hedging undedicated volumes is also warranted in order
to facilitate its short-term planning and budgeting. The Company has not hedged
significant amounts of undedicated volumes beyond 24 months. The Company may
consider long-term hedging of undedicated volumes in the future if product
prices rise to significantly higher levels. The Company believes that stability
of cash flow should be considered by separately reviewing its hedge position
relative to dedicated volumes and undedicated volumes. The following table
reflects the estimated hedge position as a percentage of the Company's
undedicated volumes:
1994 1995 1996 Thereafter Total
---- ---- ---- ---------- -----
Volumes not hedged 68% 87% 100% 100% 95%
Volumes hedged 32 13 - - 5
--- --- --- --- ---
Total undedicated volumes 100% 100% 100% 100% 100%
--- --- --- --- ---
--- --- --- --- ---
The Company believes it is important to hedge volumes dedicated to production
payments or required to repay debt. The following table reflects the estimated
hedge position as a percentage of the Company's dedicated volumes. (Volumes
dedicated to volumetric production payments are treated as hedged for purposes
of this presentation):
1994 1995 1996 1997 1998 Thereafter Total
---- ---- ---- ---- ---- ---------- -----
Volumes not hedged 29% 30% 41% 52% 51% 69% 39%
Volumes hedged 71 70 59 48 49 31 61
--- --- --- --- --- --- ---
Total dedicated
volumes 100% 100% 100% 100% 100% 100% 100%
--- --- --- --- --- --- ---
--- --- --- --- --- --- ---
Estimates of commercially recoverable oil and gas reserves and of the future net
cash flows therefrom are based upon a number of variable factors and
assumptions, such as historical production from the subject properties,
comparison with other producing properties, the assumed effects of regulation by
governmental agencies and assumptions concerning future oil and gas prices and
future operating costs, severance and excise taxes, abandonment costs,
development costs and workover and remedial costs, all of which may in fact vary
considerably from actual results. All such estimates are to some degree
speculative. Actual production, revenues, severance and excise taxes,
development expenditures, workover and remedial expenditures, abandonment
expenditures and operating expenditures with respect to the Company's reserves
will likely vary from such estimates, and such variances may be material.
30
CAPITAL EXPENDITURES. In 1991, the Company implemented its capital investment
strategy of acquiring proved properties. During 1992 and 1993, the Company
completed six major acquisitions under this strategy. The Company's
expenditures for property acquisition, exploration and development for the past
three years, including overhead related to these activities which was
capitalized, were as follows:
Years Ended December 31,
-------------------------------------
1993 1992 1991
---- ---- ----
(In Thousands)
Property acquisition costs:
Proved properties $ 121,882 70,466 13,560
Undeveloped properties 23,034 18,306 -
------- ------ ------
144,916 88,772 13,560
Exploration costs:
Direct costs 4,923 1,391 2,123
Overhead capitalized 510 906 7,600
------- ------ ------
5,433 2,297 9,723
Development costs:
Direct costs 13,424 9,315 7,180
Overhead capitalized 7,048 6,243 5,201
------- ------ ------
20,472 15,558 12,381
------- ------ ------
$ 170,821 106,627 35,664
------- ------- ------
------- ------- ------
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 of the acquisitions
for financial accounting purposes, as well as eight exploitation prospects and
three exploratory offshore blocks. In 1992, the Company's property acquisition
expenditures, as measured at the closing dates, of $88,772,000 resulted in
proved reserve additions of an estimated 63 BCF of natural gas and 5.8 million
barrels of oil, including reserves acquired as a result of gas balancing
settlements.
For the year ended December 31, 1993, finding costs were $1.26 per MCFE and
reserve replacement was 271%. This compares to $1.20 and 235% in 1992 and $1.56
and 79% in 1991. Finding costs are the total costs incurred in oil and gas
acquisition, exploration and development activities, including capitalized
overhead, for any period, divided by net additions to proved reserves on an MCFE
basis (including revisions, extensions and discoveries and purchases of reserves
in place) for such period. Reserve replacement represents estimated proved
reserve additions as a percentage of production before taking into account sales
of oil and gas reserves in place.
It is currently anticipated that the Company's 1994 expenditures for exploration
and development will be approximately $3,900,000, and $24,300,000, respectively,
including capitalized overhead of $900,000 and $5,600,000, respectively. Under
the terms of the Enron loan, 80% of direct development expenditures on the
properties subject to the loan reduce payments which would otherwise be due;
however, planned levels of capital expenditures may still be restricted if the
Company experiences lower than anticipated net cash provided by operations or
other liquidity problems.
During 1994, the Company intends to aggressively pursue a strategy of acquiring
reserves; however, no assurance can be given that the Company can locate or
finance any property acquisitions. In order to finance future acquisitions, the
Company is exploring many options including, but not limited to: a variety of
debt instruments; the issuance of net profits interests; sales of non-strategic
properties, prospects and technical information; joint venture financing; the
issuance of common or preferred equity of the Company; sale of production
payments and other nonrecourse financing; as well as additional bank financing.
Availability of these sources of capital will depend upon a number of factors,
some of which are beyond the control of the Company.
31
DIVIDENDS. To increase liquidity and fund a portion of its capital budget, the
Company deferred payment of dividends on its $15.75 Redeemable Preferred Stock
and its $2.125 Convertible Preferred Stock throughout 1991. All dividend
arrearages were eliminated at the end of 1991 when the $15.75 Redeemable
Preferred Stock and $2.125 Convertible Preferred Stock were recapitalized.
Throughout most of 1991, the Company did not have the legal ability under the
NYBCL to pay dividends. Upon completion of the recapitalization, this
restriction was removed and the Company once again has the legal ability under
the NYBCL to pay dividends, although it is subject to certain restrictive
provisions in the Indenture executed in connection with the 11 1/4% Senior
Subordinated Notes due 2003 and in the Credit Facility. The Company was
required to pay dividends, when and if declared, on its $.75 Convertible
Preferred Stock in shares of Common Stock through 1993. On February 1, 1994, a
cash dividend of $.1875 on its $.75 Convertible Preferred Stock was paid to
holders of record on January 14, 1994. On February 20, 1994 the Board of
Directors declared a cash dividend of $.1875 on the $.75 Convertible Preferred
Stock, payable May 1, 1994 to holders of record on April 8, 1994. For further
information concerning dividends, see Item 5. Market for Registrant's Common
Equity and Related Stockholder Matters and Notes 4, 6, 9 and 10 of Notes to
Consolidated Financial Statements.
OTHER MATTERS
GAS BALANCING. It is customary in the industry for various working interest
partners to produce more or less than their entitlement share of natural gas
from time to time. During 1993, the Company's net overproduced position
decreased from approximately 13 BCF to approximately 10 BCF. In 1992, the
Company's net overproduced position decreased from approximately 16 BCF to
approximately 13 BCF. In 1991, the Company's net overproduced position did not
change appreciably due to the offseting effects of gas balancing settlements and
production in excess of entitlements. The Company has entered into gas
balancing agreements for most of its imbalance position and currently estimates
that approximately 3 BCF and 2 BCF will be repaid in 1994 and 1995 under such
agreements. In the absence of a gas balancing agreement, the Company is unable
to determine when its partners may choose to make up their share of production.
If and when the Company's partners do make up their share of production, the
Company's deliverable natural gas volumes could decrease, adversely affecting
revenue and cash flow. For futher information, see Note 1 of Notes to
Consolidated Financial Statements.
UNFUNDED PENSION LIABILITIES. In 1993, in response to market conditions, the
Company lowered from 9% to 7.5% the discount rate used in determining the
actuarial present value of the projected benefit obligations under its qualified
defined benefit trusteed pension plan and its supplemental executive retirement
plan. As a result of the change in the discount rate, the Company recorded a
liability of $3,038,000 representing the unfunded liabilities of these plans and
a corresponding decrease in capital surplus. The Company does not expect the
change in discount rate to have a significant impact on future expense due to a
pension plan curtailment effected May 31, 1991. The Company currently is not
required to make a contribution to the pension plan under the minimum funding
requirements of ERISA, but may choose to do so or be required to do so in the
future.
NATURAL GAS SALES CONTRACTS. The Company had two natural gas sales contracts
with Columbia Gas Transmission Corp. (Transmission), a subsidiary of Columbia
Gas System (CGS). On July 31, 1991, CGS and Transmission filed Chapter 11
bankruptcy petitions with the United States Bankruptcy Court for the District of
Delaware. Both contracts have been rejected pursuant to the bankruptcy
proceedings. The Company has filed a proof of claim in the bankruptcy
proceeding consisting of a secured claim of $1,600,000 based on Louisiana vendor
lien laws and an unsecured claim relating to the rejection of the contracts.
The secured claim arises from Transmission's failure to pay the contract price
for a period of time prior to rejection of the contracts. The unsecured claim
was calculated on an undiscounted basis and without any assumption of mitigation
of damages through spot market sales. No prediction can be given as to when or
how these matters will ultimately be concluded.
NET OPERATING LOSS AND TAX CREDIT CARRYFORWARDS. At December 31, 1993, the
Company estimated that for United States federal income tax purposes, it had
consolidated net operating loss carryforwards of $28,439,000, depletion
carryforwards of approximately $20,174,000 and investment tax credit
carryforwards of approximately $3,885,000. The availability of some of these tax
attributes to reduce current and future taxable income of the
32
Company is subject to various limitations under the Internal Revenue Code of
1986, as amended (the Code). In particular, the Company's ability to utilize
such tax attributes could be severely restricted due to the occurrence of an
"ownership change" within the meaning of Section 382 of the Code resulting from
the 1991 recapitalization. At December 31, 1993, the Company estimated that net
operating loss and investment tax credit carryforwards would be limited to
offset current taxable income to the extent described below.
The net operating loss carryforwards, which expire in 2008, are not subject to
the provisions of Section 382 as they were generated subsequent to the ownership
change. Even though the Company is limited in its ability to use the remaining
net operating loss carryforwards under the general 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 its 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 believes that due to the amount of built-in gain as of the date of
ownership change, and the recognition of such gain through December 31, 1993,
that there will be no significant limitation on the Company's ability to use
these net operating loss carryforwards or investment tax credit carryforwards.
CHANGE IN FEDERAL CORPORATE INCOME TAX RATES. The Omnibus Budget Reconciliation
Act of 1993 increased the federal corporate tax rate from 34% to 35%
retroactively to January 1, 1993. As a result of this tax increase, the tax
benefit at December 31, 1993 on the loss from continuing operations was
approximately $167,000 less than it would have been without such increase in the
tax rate. However, due to limitations on the recognition of deferred tax assets
under FAS 109, the total tax benefit at December 31, 1993, including the tax
benefit on the extraordinary loss on extinguishment of debt, is unaffected by
the tax rate increase. The impact of the tax rate increase on the Company's
total tax expense will be recognized when future taxable income absorbs the
present unrecognized deferred tax asset.
ACCOUNTING POLICIES. In November 1992, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards No. 112, "Employers'
Accounting for Postemployment Benefits" (SFAS No. 112). This statement requires
the accrual of the estimated cost of certain postemployment benefits provided to
former employees. SFAS No. 112 is effective for years beginning after December
15, 1993. The initial effect of applying this statement is to be accounted for
as a cumulative effect of a change in accounting principle. The Company has not
determined precisely what effect, if any, the adoption of SFAS No. 112 will have
on its financial statements, but believes the effect will be immaterial because
the Company has already recorded liabilities for any of the affected costs that
would be significant.
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.
33
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, 1993 and 1992, 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, 1993. 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, 1993 and 1992, and the results
of their operations and their cash flows for each of the years in the three-year
period ended December 31, 1993 in conformity with generally accepted accounting
principles.
As discussed in Notes 8 and 13 to the 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
Denver, Colorado
February 22, 1994
34
FOREST OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
1993 1992
---- ----
(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 6,949 63,487
Accounts receivable 25,257 27,521
Other current assets 3,309 3,684
------------ ------------
Total current assets 35,515 94,692
Property and equipment, at cost:
Oil and gas properties - full cost accounting method (Note 2) 1,140,656 971,981
Buildings, transportation and other equipment 12,420 12,532
------------ ------------
1,153,076 984,513
Less accumulated depreciation, depletion and valuation allowance 787,380 725,939
------------ ------------
Net property and equipment 365,696 258,574
Investment in and advances to affiliate (Note 3) 16,451 16,847
Other assets 9,093 8,419
------------ ------------
$ 426,755 378,532
------------ ------------
------------ ------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Cash overdraft $ 3,894 5,241
Current portion of nonrecourse secured loan and
production payment obligation (Note 5) 4,371 4,462
Current portion of subordinated debentures (Note 6) 7,171 -
Senior secured notes (Note 6) - 3,926
Accounts payable 28,348 36,479
Retirement benefits payable to executives and directors (Note 13) 553 475
Accrued expenses and other liabilities:
Interest 3,817 3,895
Other 1,857 3,625
------------ ------------
Total current liabilities 50,011 58,103
Long-term bank debt (Note 4)
Nonrecourse secured loan and production payment obligation (Note 5) 25,000 -
Senior secured notes (Note 6) 70,035 22,823
Subordinated debentures (Note 6) - 56,323
Retirement benefits payable to executives and directors (Note 13) 99,272 89,175
Other liabilities 4,135 4,551
Deferred revenue (Note 7) 22,918 10,734
Deferred Federal income taxes (Note 8) 67,228 67,066
- 9,876
Shareholders' equity (Notes 4, 6, 9 and 10):
Preferred stock. Authorized 10,000,000 shares. Par value $.01 per share.
Issued 2,880,973 of $.75 Convertible Preferred Stock in 1993
(3,129,790 shares in 1992); aggregate liquidation preference of
$28,809,730 in 1993 ($31,297,900 in 1992) 15,845 17,214
Common Stock. Authorized 50,000,000 shares. Par value $.10 per share.
Issued 28,250,445 shares in 1993 (11,338,665 shares in 1992) 2,825 1,134
Class B Stock. Par value $.10 per share. (3,652,468 shares in 1992) - 365
Capital surplus 193,717 145,393
Accumulated deficit (117,656) (96,443)
Foreign currency translation (785) (427)
Treasury stock, at cost, 335,813 shares in 1993 (410,583 shares in 1992) (5,790) (7,355)
------------ ------------
Total shareholders' equity 88,156 59,881
------------ ------------
Commitments and contingencies (Notes 13 and 15)
$ 426,755 378,532
------------ ------------
------------ ------------
See accompanying notes to consolidated financial statements
35
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31,
1993 1992 1991
------------ ------------ ------------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
Revenue:
Oil and gas sales:
Gas $ 77,249 72,011 46,315
Oil and condensate 25,341 26,299 21,439
Products and other 293 929 1,122
------------ ------------ ------------
102,883 99,239 68,876
Miscellaneous, net 2,265 13,947 1,021
------------ ------------ ------------
Total revenue 105,148 113,186 69,897
Expenses:
Oil and gas production 19,540 15,865 12,548
General and administrative 12,003 11,611 9,541
Retirement benefits for executives and directors (Note 13) - - 950
Restructuring (Note 12) - - 3,585
Interest 23,729 27,800 23,306
Depreciation and depletion 60,581 46,624 38,229
Provision for impairment of oil and gas properties - - 34,000
------------ ------------ ------------
Total expenses 115,853 101,900 122,159
------------ ------------ ------------
Earnings (loss) before income taxes, cumulative effects of changes in
accounting principles and extraordinary items (10,705) 11,286 (52,262)
Income tax expense (benefit) (Note 8):
Current 254 435 455
Deferred (1,604) 3,553 (17,867)
------------ ------------ ------------
(1,350) 3,988 (17,412)
------------ ------------ ------------
Earnings (loss) before cumulative effects of changes in
accounting principles and extraordinary items (9,355) 7,298 (34,850)
Cumulative effects of changes in accounting principles (Notes 8 and 13):
Postretirement benefits, net of income tax benefit of $1,639,000 (3,183) - -
Income taxes 2,060 - -
------------ ------------ ------------
(1,123) - -
Earnings (loss) before extraordinary items (10,478) 7,298 (34,850)
Extraordinary items - extinguishment of debt, net of income tax benefit of
$4,652,000 in 1993 and tax expense of $4,895,000 in 1991 (Note 6) (10,735) - 9,502
------------ ------------ ------------
Net earnings (loss) $ (21,213) 7,298 (25,348)
------------ ------------ ------------
------------ ------------ ------------
Weighted average number of common shares outstanding 21,997 13,774 12,494
------------ ------------ ------------
------------ ------------ ------------
Net earnings (loss) attributable to common stock $ (23,463) 4,950 (30,557)
------------ ------------ ------------
------------ ------------ ------------
Primary earnings (loss) per common share (1):
Earnings (loss) before cumulative effects of changes in accounting
principles and extraordinary items $ (.53) 0 (3)
Cumulative effects of changes in accounting principles (.05) - -
------------ ------------ ------------
Earnings (loss) before extraordinary items (.58) 0 (3.21)
Extraordinary items - extinguishment of debt (.49) - 1
------------ ------------ ------------
Net earnings (loss) attributable to common stock $ (1.07) 0 (2.45)
------------ ------------ ------------
------------ ------------ ------------
(1) 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 $.29.
See accompanying notes to consolidated financial statements
36
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
$0.75 $2.125
CONVERTIBLE CONVERTIBLE
PREFERRED PREFERRED COMMON CLASS B
STOCK STOCK STOCK STOCK
------------ ------------ ------------ ------------
(IN THOUSANDS)
Balance December 31, 1990 $ - 57,500 873 377
Net loss - - - -
+$2.125 CONVERTIBLE PREFERRED
Stock reclassified as $.75
Convertible Preferred
Stock (Note 9) 12,650 (57,500) - -
Redeemable Preferred Stock
acquired for $.75 Convertible
Preferred Stock (Note 9) 4,396 - - -
+$.75 CONVERTIBLE PREFERRED STOCK
issue costs - - - -
Warrants issued in exchange
offers (Note 10) - - - -
Redeemable Preferred Stock - - - -
dividends (Note 9) - - - -
Treasury stock contributed to
the Retirement Savings
Plan and other 234 - 78 (2)
Foreign currency translation - - - -
------------ ------------ ------------ ------------
Balance December 31, 1991 17280 - 951 375
Net earnings - - - -
+$.75 CONVERTIBLE PREFERRED
Stock dividends paid in
Common Stock (Note 9) - - 153 -
Conversions of $.75 Convertible
Preferred Stock to
Common Stock (66) - 4 -
Issuance of Common Stock in
payment of executive
retirement liability (Note 13) - - 16 -
Treasury stock contributed to
the Retirement Savings
Plan and other - - 10 (10)
Foreign currency translation - - - -
------------ ------------ ------------ ------------
Balance December 31, 1992 17214 - 1,134 365
Net loss - - - -
Common Stock issued, net of
offering costs (Note 10) - - 1,108 -
+$.75 CONVERTIBLE PREFERRED
Stock dividends paid in
Common Stock (Note 9) - - 64 -
Conversions of $.75 Convertible
Preferred Stock to
Common Stock (1,369) - 87 -
Reclassification of Class B to
Common Stock (Note 10) - - 396 (360)
Exercise of employee stock
options (Note 10) - - 13 -
Stock issued to the Retirement
Savings Plan for profit-
sharing contributions (Note 13) - - 18 -
Unfunded pension liability (Note 13) - - - -
Treasury stock contributed to
the Retirement Savings
Plan and other - - 5 (5)
Foreign currency translation - - - -
------------ ------------ ------------ ------------
Balance December 31, 1993 $ 15845 - 2,825 -
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
ACCUMU- FOREIGN
CAPITAL LATED CURRENCY TREASURY
SURPLUS DEFICIT TRANSLATION STOCK
------------ ------------ ------------ ------------
Balance December 31, 1990
Net loss 92,511 (78,393) 2,074 (16,485)
+$2.125 CONVERTIBLE PREFERRED - (25,348) - -
Stock reclassified as $.75
Convertible Preferred
Stock (Note 9)
Redeemable Preferred Stock 44,850 - - -
acquired for $.75 Convertible
Preferred Stock (Note 9)
+$.75 CONVERTIBLE PREFERRED STOCK 22,500 - - -
issue costs
Warrants issued in exchange (1,500) - - -
offers (Note 10)
Redeemable Preferred Stock 373 - - -
dividends (Note 9) - - - -
Treasury stock contributed to (5,209) - - -
the Retirement Savings
Plan and other
Foreign currency translation (4,456) - - 4,915
- - 402 -
------------ ------------ ------------ ------------
Balance December 31, 1991
Net earnings 149,069 (103,741) 2,476 (11,570)
+$.75 CONVERTIBLE PREFERRED - 7,298 - -
Stock dividends paid in
Common Stock (Note 9)
Conversions of $.75 Convertible (153) - - -
Preferred Stock to
Common Stock
Issuance of Common Stock in 62 - - -
payment of executive
retirement liability (Note 13)
Treasury stock contributed to 173 - - -
the Retirement Savings
Plan and other
Foreign currency translation (3,758) - - 4,215
- - (2,903) -
------------ ------------ ------------ ------------
Balance December 31, 1992
Net loss 145,393 (96,443) (427) (7,355)
Common Stock issued, net of - (21,213) - -
offering costs (Note 10)
+$.75 CONVERTIBLE PREFERRED 50,398 - - -
Stock dividends paid in
Common Stock (Note 9)
Conversions of $.75 Convertible (64) - - -
Preferred Stock to
Common Stock
Reclassification of Class B to 1,282 - - -
Common Stock (Note 10)
Exercise of employee stock (36) - - -
options (Note 10)
Stock issued to the Retirement 383 - - -
Savings Plan for profit-
sharing contributions (Note 13)
Unfunded pension liability (Note 13) 597 - - -
Treasury stock contributed to (3,038) - - -
the Retirement Savings
Plan and other
Foreign currency translation (1,198) - - 1,565
- - (358) -
------------ ------------ ------------ ------------
Balance December 31, 1993 193,717 (117,656) (785) (5,790)
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
See accompanying notes to consolidated financial statements
37
FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31,
1993 1992 1991
--------- --------- ---------
(IN THOUSANDS)
Cash flows from operating activities:
Earnings (loss) before cumulative effects of changes in
accounting principles and extraordinary items $ (9,355) 7,298 (34,850)
Adjustments to reconcile earnings (loss) before cumulative effects of
changes in accounting principles and extraordinary items
to net cash provided by operating activities:
Depreciation and depletion 60,581 46,624 38,229
Provision for impairment of oil and gas properties - - 34,000
Deferred Federal income tax expense (benefit) (1,604) 3,553 (17,867)
Gain on curtailment of pension plan - - (806)
Other, net 3,045 3,387 625
--------- --------- ---------
52,667 60,862 19,331
Net changes in current assets and liabilities:
(Increase) decrease in accounts receivable 2,264 (3,447) 4,795
(Increase) decrease in other current assets 375 (1,903) 1,020
Increase (decrease) in accounts payable (12,668) 13,090 (8,678)
Increase (decrease) in accrued expenses and other liabilities (1,078) 1,772 (898)
--------- --------- ---------
Net cash provided by operating activities 41,560 70,374 15,570
Cash flows from investing activities:
Capital expenditures for property and equipment (171,166) (107,425) (36,449)
Proceeds of sales of property and equipment, net 2,997 25,730 15,658
Increase in other assets, net (1,965) (1,659) (755)
--------- --------- ---------
Net cash used by investing activities (170,134) (83,354) (21,546)
Cash flows from financing activities:
Proceeds of long-term bank debt 25,000 9,623 9,000
Repayments of long-term bank debt - (9,623) (23,000)
Proceeds of nonrecourse secured loan 57,400 - -
Proceeds of production payment - 28,805 -
Repayments of production payment (5,980) (1,520) -
Redemptions and repurchases of subordinated debentures and secured notes (148,918) (1,115) -
Proceeds of volumetric production payments 40,468 45,057 49,180
Amortization of deferred revenue (40,306) (18,190) (8,981)
Proceeds of common stock offering, net of offering costs 51,506 - -
Issuance of senior subordinated notes, net of offering costs 95,827 - -
Deferred debt and exchange offer costs (1,336) (285) (6,400)
Increase (decrease) in cash overdraft (1,347) 2,963 509
Increase (decrease) in other liabilities, net (266) 1,998 (2,389)
--------- --------- ---------
Net cash provided by financing activities 72,048 57,713 17,919
Effect of exchange rate changes on cash (12) (110) 16
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents (56,538) 44,623 11,959
Cash and cash equivalents at beginning of year 63,487 18,864 6,905
--------- --------- ---------
Cash and cash equivalents at end of year $ 6,949 63,487 18,864
--------- --------- ---------
--------- --------- ---------
Cash paid during the year for:
Interest $ 23,123 26,079 22,675
--------- --------- ---------
--------- --------- ---------
Income taxes $ 452 177 672
--------- --------- ---------
--------- --------- ---------
See accompanying notes to consolidated financial statements.
38
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
- --------------------------------------------------------------------------------
BASIS OF CONSOLIDATION - The consolidated financial statements include the
accounts of Forest Oil Corporation (the Company) and its wholly-owned
subsidiaries. Significant intercompany balances and transactions are
eliminated. The Company's investment in CanEagle Resources Corporation
(CanEagle) is accounted for using the equity method (See Note 3).
CASH EQUIVALENTS - For purposes of the statements of cash flows, the Company
considers all debt instruments with original maturities of three months or less
to be cash equivalents.
PROPERTY AND EQUIPMENT - The Company uses the full cost method of accounting for
oil and gas properties. Separate cost centers are maintained for each country
in which the Company has operations. 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. Costs applicable to
each cost center, including capitalized costs as wells as estimated costs of
future development, surrender and abandonment, are depleted using the units of
production method. Unusually significant investments in seismic data and
unproved properties, including related capitalized interest costs, are not
depleted pending the determination of the existence of proved reserves and the
commencement of sales from the properties. As of December 31, 1993 and 1992,
there were undeveloped property costs of $41,216,000 and $18,306,000,
respectively, in the United States which were not being depleted, all of which
relate to property acquisitions in 1992 and 1993. At December 31, 1991 there
were no costs in any cost centers which were not subject to depletion.
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 MCF of natural
gas. Depletion per unit of production (MCFE) for each of the Company's cost
centers was as follows:
UNITED STATES CANADA
------------- ------
1993 $ 1.19 -
1992 1.21 1.19
1991 1.28 1.37
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 of
each of the cost centers, the accompanying financial statements include a
provision for impairment of oil and gas property costs of $15,000,000 in the
United States and $19,000,000 in Canada in 1991. There was no impairment of oil
and gas property costs required to be recorded in 1993 or 1992.
No gain or loss is recognized on the sale of oil and gas properties except in
the case of properties involving significant remaining reserves. Proceeds from
sales of insignificant reserves and undeveloped properties are applied to reduce
the costs in the cost centers.
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.
39
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONT'D):
- --------------------------------------------------------------------------------
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 tax bases and financial reporting bases of all other assets
and liabilities. Temporary differences are principally the result of certain
development, exploration and other costs which are deducted for income tax
purposes but capitalized for financial accounting purposes.
FOREIGN CURRENCY TRANSLATION - Balance sheet accounts of Canadian activities are
translated into United States dollars using the year-end exchange rates. Income
and expense items have been translated at rates applicable during each year.
Adjustments resulting from these translations are accumulated in a separate
component of shareholders' equity.
GAS REVENUE - The Company uses the sales method of accounting for amounts
received from natural gas sales. Under this method, all proceeds from
production credited to the Company are recorded as revenue until such time as
the Company has produced its share of related estimated remaining reserves.
Thereafter, additional amounts received are recorded as a liability.
As of December 31, 1993 the Company had produced approximately 10 BCF more than
its entitled share of production. The undiscounted value of this imbalance is
approximately $17,000,000 using the lower of the price received for the natural
gas, the current market price or the contract price, as applicable. Amounts
received for approximately 7 BCF of this production have been recorded as
revenue and as reductions of the Company's reserve quantities and reserve values
described in Note 19. Amounts received for the remaining 3 BCF of this
production have been recorded as a liability as this volume exceeds the
Company's share of the related estimated remaining reserves. The liability is
recorded in accordance with the settlement provisions of the applicable gas
balancing agreements and amounted to approximately $3,887,000 at December 31,
1993.
ENERGY SWAPS AND OTHER FINANCIAL ARRANGEMENTS - In order to hedge against the
effects of declines in oil and natural gas prices, the Company enters into
energy swap agreements and other financial arrangements with third parties. 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, 1993, 1992 and 1991, the Company
incurred swap gains (losses) of $(2,050,000), $(1,642,000) and $3,564,000,
respectively. The Company recognizes gains or losses on such agreements as
adjustments to revenue recorded for the related production.
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 $2,250,000 in 1993, $2,348,000 in 1992, and $5,209,000 in 1991.
Common share equivalents include, when applicable, dilutive stock options and
warrants using the treasury stock method.
Fully diluted earnings per share assumes, 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) the additional dilutive effect of stock
options and warrants. The effects of these assumptions were anti-dilutive in
1993 and 1991. The weighted average number of shares outstanding on a fully-
diluted basis was 26,515,000 for the year ended December 31, 1992.
40
(2) ACQUISITIONS:
- --------------------------------------------------------------------------------
On May 18, 1993 and December 10, 1993, the Company purchased interests in
properties from Atlantic Richfield Company (ARCO) for approximately $60,862,000.
In conjunction with the acquisitions, the Company sold volumetric production
payments from certain of the ARCO properties for approximately $40,468,000 (net
of fees). On December 14, 1993, the Company purchased interests in offshore
properties in the West Cameron/Eugene Island area from a private company for
approximately $24,050,000. On December 30, 1993, the Company purchased
interests in properties in the Loma Vieja field in south Texas for approximately
$59,458,000. In conjunction with the acquisitions, the Company entered into a
nonrecourse secured loan agreement for $51,600,000. The remainder of the
purchase price for these two acquisitions, $31,908,000, was financed through
internal funds and from funds obtained under the Company's secured master credit
facility. The Company's results of operations for the year ended December 31,
1993 include the effects of the first ARCO acquisition since May 1, 1993 and the
West Cameron/Eugene Island properties and the second ARCO acquisition since
December 1, 1993.
On February 1, 1992, Forest I Development Company, a wholly-owned subsidiary of
the Company, purchased substantially all of the assets of Harbert Energy
Corporation and its associated entities in an acquisition accounted for as a
purchase. The purchase price of $40,400,000 consisted of payment of
approximately $7,120,000 in cash (including acquisition costs), assumption by
Forest of certain liabilities, and the sale of a dollar-denominated production
payment which was recorded at its present value of $28,805,000. On July 31,
1992, the Company purchased Transco Exploration and Production Company (TEPCO)
for approximately $45,000,000. In conjunction with the acquisition, the Company
sold a volumetric production payment from certain of the TEPCO properties for
approximately $38,500,000 (net of fees). In addition, the Company issued a
$2,000,000 promissory note to Transco Energy Corporation as part of the purchase
price. Approximately $4,062,000 was paid in cash, including acquisition costs.
The Company's results of operations for the year ended December 31, 1992 include
the effects of the Harbert and TEPCO acquisitions since February 1, 1992 and
July 31, 1992, respectively.
(3) INVESTMENT IN AND ADVANCES TO AFFILIATE:
- --------------------------------------------------------------------------------
In May 1992, the Company transferred substantially all of its Canadian oil and
gas properties to a wholly-owned Canadian subsidiary, Forest Canada I
Development Ltd. (FCID). On September 30, 1992, FCID sold its Canadian assets
and related operations to CanEagle for approximately $51,250,000 in Canadian
funds ($41,000,000 U.S.). CanEagle was formed for the purpose of acquiring the
assets and related operations of FCID. An independent third party financed the
purchase by CanEagle. In the transaction, FCID received cash of approximately
$28,000,000 CDN ($22,400,000 U.S.), net of expenses, and provided financing to
the third party in the aggregate principal amount of $22,000,000 CDN
($17,600,000 U.S.).
In connection with the transaction, CanEagle issued to the third party (a) a
$19,000,000 CDN senior debenture, secured by its oil and gas properties, (b) a
$6,000,000 CDN subordinated debenture, secured by its oil and gas properties and
subordinated to the senior debenture, (c) a $16,000,000 CDN senior subordinated
note, unsecured and subordinated to the debentures, (d) convertible notes for
$6,250,000 CDN, unsecured and subordinated to the debentures and the senior
subordinated note, and (e) preferred stock for $4,000,000 CDN. A Canadian bank
provided financing to the third party secured by a pledge of the senior
debenture. Forest's financing to the third party is secured by a pledge of the
subordinated debenture and the senior subordinated note. The notes received by
Forest from the third party, the subordinated debenture and the senior
subordinated note were due March 31, 1998 and bore interest at 9% per annum
payable quarterly.
As part of the transaction, Forest retained 100% of the common equity of
CanEagle and granted an option to a third party to purchase 80% of the common
equity of CanEagle for nominal consideration. The original option lapsed
unexercised in December 1992. Forest subsequently agreed to sell all of the
common equity interest to the third party, subject to certain revisions to
aspects of CanEagle's capital structure. This sale was completed on September
29, 1993 for nominal consideration.
41
(3) INVESTMENT IN AND ADVANCES TO AFFILIATE (CONT'D):
- --------------------------------------------------------------------------------
On September 29, 1993, Forest exchanged the $16,000,000 CDN senior subordinated
note plus $780,000 CDN accrued interest thereon for 15,400,000 shares of Class A
Preferred Shares and 1,400,000 shares of Class B Preferred Shares of CanEagle.
The Class A and Class B Preferred Shares have liquidation preference rights of
$1.00 CDN per share. The Class A Preferred Shares are entitled to annual fixed
cumulative preferential cash dividends of $.03 per share, payable quarterly.
Dividends may be paid through issuance of noninterest-bearing promissory notes
due not later than September 30, 1998. Class B Preferred Shares are entitled to
an annual $.03 fixed cumulative cash dividend payable only after all Class A
Preferred Shares have been redeemed.
CanEagle may redeem first the Class A and then the Class B Preferred Shares at
$1.00 CDN per share plus all accumulated but unpaid dividends thereon at any
time subsequent to issuance, on a pro rata basis from all holders of each issue,
but is required to redeem all of the then outstanding shares of both issues on
or before September 30, 1998.
While any of the Class A and Class B Preferred Shares are outstanding, CanEagle
is prohibited from making dividends or distributions on, or redeeming or
purchasing any of its common shares, issuing any additional preferred shares,
incurring any indebtedness other than as permitted under the restated articles
of incorporation or undertaking certain other prohibited transactions unless
unanimously approved by holders of the Class A shares.
No gain was recognized as a result of the CanEagle transaction because
collection of the remaining sales price was not reasonably assured. Due to its
continuing financial interest in CanEagle, the Company is accounting for its
investment in CanEagle under the equity method. Accordingly, losses will be
recognized to the extent that such losses exceed (a) amounts attributable to
securities subordinate to the Company's interest, and (b) the basis difference
of $780,000 CDN attributable to the 1993 capital restructuring of CanEagle.
Under this method, no portion of the CanEagle loss was required to be recorded
by the Company in 1993.
Earnings related to the Company's interest in CanEagle will be recognized only
if realization is assured. Accordingly, amounts received as interest on the
subordinated note during 1993 (approximately $540,000 CDN) were recorded as a
reduction of the Company's investment in and advances to CanEagle. No dividends
were paid on the Class A Preferred Shares in 1993.
The excess of the carrying value of properties sold over the cash received, or
approximately $16,451,000 U.S. at December 31, 1993, represents Forest's
investment in CanEagle.
In March 1994, the Company pledged its CanEagle securities as collateral for a
$4,000,000 loan from The Chase Manhattan Bank, NA due June 1, 1994.
42
(3) INVESTMENT IN AND ADVANCES TO AFFILIATE (CONT'D):
- --------------------------------------------------------------------------------
CanEagle reports its annual results on a fiscal year ending on September 30.
Condensed financial statement information for CanEagle as of September 30, 1993
and 1992 and for the year ended September 30, 1993 is as follows:
BALANCE SHEET
SEPTEMBER 30,
---------------------
1993 1992
------ ------
(In Thousands of Canadian dollars)
ASSETS
Current assets - cash and accounts receivable $ 4,637 20
Oil and gas properties:
Proved 21,017 39,386
Unproved 29,086 12,000
------ ------
50,103 51,386
Less accumulated depreciation and depletion 4,568 -
------ ------
Net oil and gas properties 45,535 51,386
Note receivable 2,980 -
------ ------
$53,152 51,406
------ ------
------ ------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 4,650 136
Current portion of senior debenture 16,300 5,700
------ ------
20,950 5,836
Senior debenture - 13,300
Subordinated debenture 6,000 6,000
Senior note - 16,000
Convertible notes - 6,250
Other liabilities 91 -
Shareholders' equity:
Common stock 20 20
Preferred stock:
Class A 15,400 -
Series A - 4,000
Class B 12,500 -
Series B 600 -
Accumulated deficit (2,409) -
------ ------
Total shareholders' equity 26,111 4,020
------ ------
$53,152 51,406
------ ------
------ ------
43
(3) INVESTMENT IN AND ADVANCES TO AFFILIATE (CONT'D):
- --------------------------------------------------------------------------------
STATEMENT OF OPERATIONS
YEAR ENDED
SEPTEMBER 30, 1993
------------------
(In Thousands of Canadian dollars)
Oil and gas sales $ 8,819
Expenses:
Oil and gas production 1,861
General and administrative 514
Interest 3,812
Depreciation and depletion 4,660
------
Total expenses 10,847
Loss before income taxes (2,028)
Income tax expense 101
------
Net loss (2,129)
Preferred stock dividend requirements (280)
-------
Net loss attributable to common stock $(2,409)
-------
-------
Substantial uncertainty exists regarding whether CanEagle is a going concern due
to the required principal payment of $16,300,000 on its Senior Debenture due
June 30, 1994. CanEagle is in the process of refinancing the Senior Debenture
with its lender, but there is no assurance that such refinancing can be
completed on mutually acceptable terms prior to the due date. The above
condensed financial statements do not include any adjustments relating to the
ultimate outcome of this uncertainty.
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).
(A) Unaudited information with respect to costs incurred by CanEagle for oil
and gas exploration and development activities is as follows:
YEAR ENDED
SEPTEMBER 30, 1993
------------------
(In Thousands of Canadian Dollars)
Property acquisition costs $ 44
Exploration costs 642
Development costs 1,670
-----
Total $2,356
-----
-----
(B) Unaudited information with respect to CanEagle's estimated proved oil and
gas reserves at September 30, 1993 and 1992 follows. Such estimates are
inherently imprecise and may be subject to substantial revisions.
SEPTEMBER 30, SEPTEMBER 30,
1993 1992
------------ -------------
Proved reserves:
Oil and condensate (MBBLS) 3,795 2,075
Gas (MMCF) 18,159 22,173
Proved developed reserves:
Oil and condensate (MBBLS) 2,930 2,036
Gas (MMCF) 10,948 11,290
44
(3) INVESTMENT IN AND ADVANCES TO AFFILIATE (CONT'D):
- --------------------------------------------------------------------------------
(C) The standardized measure of discounted future net cash flows of
CanEagle, calculated in accordance with the provisions of SFAS 69 is as
follows:
SEPTEMBER 30, SEPTEMBER 30,
1993 1992
------------ -------------
(In Thousands of Canadian Dollars)
Standardized measure of
discounted future net cash flows $37,854 40,623
------ ------
------ ------
(4) LONG-TERM BANK DEBT:
- --------------------------------------------------------------------------------
In December 1993, the Company entered into a secured master credit facility (the
Credit Facility) with The Chase Manhattan Bank, NA. (Chase) as agent for a group
of banks. Under the Credit Facility, the Company may borrow up to $17,500,000
for acquisition or development of proved oil and gas reserves, which amount is
subject to semi-annual redetermination, and up to $17,500,000 for working
capital and general corporate purposes. 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, and a
negative pledge on remaining assets. Borrowings under the Credit Facility bear
interest at the Chase base rate plus 3/8 of 1% or 1,2,3 or 6 month LIBOR plus 1
and 5/8%, payable quarterly. A commitment fee of 1/2 of 1% is charged on unused
availability. The maturity date of the Credit Facility is December 31, 1996.
Under the terms of the Credit Facility, the Company is subject to certain
covenants, including restrictions or requirements with respect to working
capital, net cash flow, additional debt, asset sales, mergers, cash dividends on
capital stock and reporting responsibilities.
At December 31, 1993 the outstanding balance under the credit facility was
$25,000,000 at an interest rate of 6.375%. The Company did not meet the test
imposed by the working capital covenant of the Credit Facility; compliance with
this covenant was waived by Chase at December 31, 1993.
(5) NONRECOURSE SECURED LOAN AND PRODUCTION PAYMENT OBLIGATION:
- --------------------------------------------------------------------------------
NONRECOURSE SECURED LOAN:
On December 30, 1993, the Company entered into a nonrecourse secured loan
agreement which bears annual interest at the rate of 12.5%, arranged by Enron
Finance Corp., an affiliate of Enron Gas Services (the Enron loan).
Approximately $51,600,000 was advanced on December 30, 1993 to provide financing
for a portion of the West Cameron/Eugene Island and Loma Vieja acquisitions.
Another $5,800,000 of the available balance was advanced on December 30, 1993 to
fund a portion of the development projects which will be undertaken by the
Company on the properties pledged as security for the loan. Under the terms of
the Enron loan, additional funds may be advanced to fund additional development
projects which will be undertaken by the Company on the properties pledged as
security for the loan. The loan amount of $57,400,000 was recorded as a
liability of $53,101,000 to reflect conveyance to the lender of a 20% interest
in the net profits, as defined, of the Loma Vieja properties. The loan discount
of $4,299,000 will be amortized over the life of the loan using the effective
interest method.
Payments of principal and interest under the Enron 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. The Company's current
estimate, based on expected production and prices, budgeted capital expenditure
levels and expected discount amortization, is that 1994 payments will reduce the
recorded liability by approximately $983,000; this amount is included in current
liabilities. Estimated liability reductions for 1995 through 1997,
45
(5) NONRECOURSE SECURED LOAN AND PRODUCTION PAYMENT OBLIGATION (cont'd):
- -------------------------------------------------------------------------------
under the same production, pricing, capital expenditure and amortization
scenario, are $12,385,000, $20,485,000, and $19,248,000, respectively.
Payments, if any, under the net profits conveyance will commence upon repayment
of the principal amount of the Enron loan and will cease when the lender has
received an internal rate of return, as defined, of 18% (15.25% through December
31, 1995). Properties to which approximately 22% of the Company's estimated
proved reserves are attributable, on an MCF equivalent basis, are dedicated to
repayment of the Enron loan.
PRODUCTION PAYMENT OBLIGATION:
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, 1993 the
remaining recorded liability was $21,305,000. Under the terms of the dollar-
denominated production payment agreement entered into in 1992 in connection with
the Harbert acquisition, Forest I Development 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's current estimate, based on expected production and
prices, budgeted capital expenditure levels and expected discount amortization,
is that 1994 payments will reduce the recorded liability by approximately
$3,388,000; this amount is included in current liabilities. Estimated liability
reductions for 1995 through 1998, under the same production, pricing, capital
expenditure and discount scenario, are $1,949,000, $3,522,000, $4,492,000 and
$2,340,000, respectively. Properties to which approximately 7% of the Company's
estimated proved reserves are attributable, on an equivalent barrel basis, are
pledged under the production payment financing through July 1999.
(6) SENIOR SECURED NOTES AND SUBORDINATED DEBENTURES:
SENIOR SECURED NOTES:
The Senior Secured Notes were issued in 1991 in connection with the Company's
recapitalization and were redeemed in full during 1993. Amounts outstanding at
December 31, 1992 were as follows (In Thousands):
Principal amount $ 65,773
Unamortized original issue discount (5,524)
-------
60,249
Less current portion (3,926)
-------
$ 56,323
-------
-------
Accretion of the original issue discount relating to the Senior Secured Notes
was calculated using the effective interest method over the life of the issue.
The Senior Secured Notes bore interest at 12-3/4%, were due June 1, 1998, and
were initially secured by liens on substantially all of the Company's oil and
gas properties in the United States, including all reserves attributable
thereto. The provisions of the Senior Secured Notes contained restrictions on
dividends or cash distributions on or purchases of capital stock, prohibited
payment of cash dividends on the Company's Common Stock and Class B Stock prior
to January 1, 1994 and were subject to required purchase provisions upon
occurrence of certain specified events.
Pursuant to the provisions of the Senior Secured Notes, the Company was required
to make an offer to purchase Senior Secured Notes with 50% of the net cash
proceeds (as defined) of the ONEOK litigation. (See Note 11). The amount of
Senior Secured Notes tendered pursuant to such offer was $3,926,000. The
purchase resulted in a loss of $614,000 which was recorded as a reduction of
miscellaneous net revenue in 1992.
46
(6) SENIOR SECURED NOTES AND SUBORDINATED DEBENTURES (cont'd):
- -------------------------------------------------------------------------------
The Senior Secured Notes were senior in right of payment to the 13-5/8%
Debentures, 12-1/2% Debentures, 13-7/8% Debentures and 5-1/2% Debentures.
The redemption of the Senior Secured Notes was completed using the net proceeds
from a Common Stock offering and a portion of the proceeds from the sale of 11-
1/4% Senior Subordinated Notes described below. The outstanding principal value
of the Senior Secured Notes of $61,847,000 at December 31, 1992 was redeemed
during 1993, resulting in a loss of $9,419,000.
Subordinated Debentures:
Subordinated debentures outstanding at December 31 were as follows:
1993 1992
------ ------
(In Thousands)
11-1/4% Senior Subordinated Notes,
net of unamortized original issue
discount of $728,000 $99,272 -
13-5/8% Debentures - 72,374
12-1/2% Debentures - 4,408
13-7/8% Debentures - 4,914
5-1/2% Debentures 7,171 7,479
------- -------
106,443 89,175
Less current portion (7,171) -
------- -------
$99,272 89,175
------- -------
------- -------
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 Senior Subordinated Notes will be 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 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.
The 13-5/8% Debentures were due September 15, 1998. The outstanding balance of
the 13-5/8% Debentures of $72,374,000 at December 31, 1992 was redeemed during
1993, resulting in a loss of $5,839,000.
The 12-1/2% Debentures were due May 1, 1999. The outstanding balance of the 12-
1/2% Debentures of $4,408,000 at December 31, 1992 was redeemed during 1993,
resulting in a loss of $78,450.
47
(6) SENIOR SECURED NOTES AND SUBORDINATED DEBENTURES (CONT'D):
- -------------------------------------------------------------------------------
The 13-7/8% Debentures were due June 1, 2000. The outstanding balance of the
13-7/8% Debentures of $4,914,000 at December 31, 1992 was redeemed during 1993,
resulting in a loss of $53,000.
During 1993, the Company purchased $308,000 principal amount of its 5-1/2%
Convertible Subordinated Debentures, resulting in a gain of $2,000. The
remaining balance of $7,171,000 was paid in full on the February 1, 1994 due
date.
In 1991, the Company consummated exchange offers pursuant to which the Company's
outstanding debt was exchanged for Senior Secured Notes and warrants to purchase
Common Stock. Holders of $62,010,000 principal amount of the Company's 12-1/2%
Debentures, 13-7/8% Debentures and 13-5/8% Debentures accepted the Company's
exchange offers, which were accounted for as extinguishments of debt.
Therefore, the Company recognized an extraordinary gain on such transactions
equal to the excess of the carrying amount of the debentures exchanged over the
estimated market value of the Senior Secured Notes and Warrants issued. The
gain on the transactions of $14,397,000, reduced by applicable income taxes of
$4,895,000, was recorded as an extraordinary gain on extinguishment of debt in
1991.
(7) DEFERRED REVENUE:
- --------------------------------------------------------------------------------
In April 1991, the Company sold a volumetric production payment from the
Company's interest in four properties to Enron Reserve Acquisition Corporation
(Enron) for net proceeds of $43,680,000. The production payment agreement
covered approximately 30 BCF of natural gas to be delivered over six years at an
average price of $1.38 per MMBTU. From November 1991 through February 1992, the
Company acquired additional interests in one of the subject properties for
$15,465,000 and sold a second volumetric production payment to Enron for net
proceeds of $12,035,000. This second production payment covered approximately 9
BCF of natural gas to be delivered over four years at an average price of $1.26
per MMBTU. In connection with the purchase of TEPCO in July 1992, a volumetric
production payment from certain of the TEPCO properties was sold to Enron for
net proceeds of $38,522,000. This production payment covered approximately 18
BCF of natural gas at an average price of $1.39 per MMBTU and 770,000 barrels of
oil at an average price of $15.99 per barrel to be delivered over four years.
In connection with the purchase of interests in properties from ARCO in May
1993, a volumetric production payment from certain of the ARCO properties was
sold to Enron for net proceeds of $27,260,000. This production payment covered
approximately 13.1 BCF of natural gas at an average price of $1.92 per MMBTU to
be delivered over three 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. The Company may grant liens on
properties subject to this production payment agreement, but it must notify
prospective lienholders that their rights are subject to the prior rights of the
production payment owner.
In connection with the purchase of interests in properties from ARCO in December
1993, a volumetric production payment from certain of the ARCO proerties was
sold to Enron for net proceeds of $13,207,000. This production payment covered
approximately 7.3 BCF of natural gas at an average price of $1.68 per MMBTU to
be delivered over 8 years.
The Company is responsible for royalties and for production costs associated
with operating the properties subject to the production payment agreements.
48
(7) DEFERRED REVENUE (CONT'D):
- --------------------------------------------------------------------------------
Amounts received were recorded as deferred revenue. Annual amortization of
deferred revenue, based on the scheduled deliveries under the production payment
agreements, is as follows:
SCHEDULED DELIVERIES
--------------------------
ANNUAL NATURAL GAS OIL
AMORTIZATION (MCF) (BARRELS)
------------ ----------- ---------
(In Thousands)
1994 $34,935 19,422 218
1995 19,797 10,425 174
1996 7,278 3,534 87
1997 2,390 1,361 -
Thereafter 2,828 1,551 -
------ ------ ---
$67,228 36,293 479
------ ------ ---
------ ------ ---
The Company includes reserves dedicated to the volumetric production payments in
its estimated proved oil and gas reserves. (See Note 19.)
(8) 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 is determined as of January 1, 1993 and is 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:
1993 1992 1991
---- ---- ----
(In Thousands)
Tax expense (benefit) at 35% (34% for 1992 and
1991) of earnings (loss) before income taxes,
changes in accounting and extraordinary
gain (loss) $ (3,747) 3,837 (17,769)
Change in the balance of the valuation
allowance for deferred tax assets 2,034 - -
Other 363 151 357
------ ----- ------
Total income tax expense (benefit) $ (1,350) 3,988 (17,412)
------ ----- ------
------ ----- ------
The Omnibus Budget Reconciliation Act of 1993 increased the federal corporate
tax rate from 34% to 35% retroactively to January 1, 1993. As a result of this
tax increase, the tax benefit at December 31, 1993 on the loss from continuing
operations was approximately $167,000 less than it would have been without such
increase in the tax rate. However, due to limitations on the recognition of
deferred tax assets under SFAS No. 109, the total tax benefit at December 31,
1993, including the tax benefit on the extraordinary loss on extinguishment of
debt, is unaffected by the tax rate increase. The impact of the tax rate
increase on the Company's total tax expense will be recognized when future
taxable income absorbs the present unrecognized deferred tax asset.
49
(8) INCOME TAXES (CONT'D):
- --------------------------------------------------------------------------------
Income taxes that are classified as deferred are generally the result of
recognizing income and expenses at different times for financial and tax
reporting. These differences result from recording proceeds from the sale of
properties in the full cost pool, capitalization of certain development,
exploration and other costs under the full cost method of accounting and the
provision for impairment of oil and gas properties for financial accounting
purposes.
The components of the net deferred tax liability, computed in accordance with
SFAS No. 109 are as follows:
DECEMBER 31, 1993 JANUARY 31, 1993
----------------- ----------------
(In Thousands)
Deferred tax assets:
Accounts receivable, due to allowance for doubtful accounts $ 428 455
Current and long term liabilities due to accrual for retirement benefits 1,644 1,709
Current and long term liabilities due to accrual for medical benefits 1,688 -
Net operating loss carryforward 9,953 2,821
Depletion carryforward 7,061 6,723
Contribution carryforward 348 619
Investment tax credit carryforward 3,885 4,178
Alternative minimum tax credit carryforward 2,206 2,215
Other 96 119
------ ------
Total gross deferred tax assets 27,309 18,839
Less valuation allowance (7,268) (5,234)
------ ------
Net deferred tax assets 20,041 13,605
Deferred tax liabilities:
Full cost pool, due principally to capitalized expenditures (20,041) (21,421)
------ ------
Net deferred tax liability $ - (7,816)
------ ------
------ ------
The valuation allowance for deferred tax assets as of January 1, 1993 was
$5,234,000. The net change in the total valuation allowance for the year ended
December 31, 1993 was an increase of $2,034,000.
The Alternative Minimum Tax (AMT) credit carryforward available to reduce future
Federal regular taxes aggregated $2,206,000 at December 31, 1993. This amount
may be carried forward indefinitely. Regular and AMT net operating loss
carryforwards at December 31, 1993 were $28,439,000 and $23,916,000,
respectively, and will expire in the years indicated below:
REGULAR AMT
------- ---
(In Thousands)
2000 $ 2,665 4,127
2005 8,307 -
2008 17,467 19,789
------ ------
$28,439 23,916
------ ------
------ ------
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 $3,885,000 at December 31, 1993 and expire at various dates
through the year 2001. Percentage depletion carryforwards available to reduce
future Federal taxable income aggregated $20,174,000 at December 31, 1993. This
amount may be carried forward indefinitely. The net operating loss and
investment tax credit carryforwards have been recognized as a reduction of
deferred taxes, subject to a valuation allowance.
50
(8) INCOME TAXES (cont'd):
- --------------------------------------------------------------------------------
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 severely restricted due to the occurrence of an "ownership
change" within the meaning of Section 382 of the Internal Revenue Code resulting
from the Recapitalization. At December 31, 1993, the Company estimated that
net operating loss and investment tax credit carryforwards would be limited to
offset current taxable income to the extent described below.
The net operating loss carryforwards which expire in 2008 are not subject to the
provisions of Section 382 as they were generated subsequent to the ownership
change. Even though the Company is limited in its ability to use the remaining
net operating loss carryovers under the general 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 its 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 believes that due to the amount of built-in gain as of the date of
ownership change, and the recognition of such gain through December 31, 1993,
there is no significant limitation on the Company's ability to use these net
operating loss carryforwards or investment tax credit carryforwards.
(9) PREFERRED STOCK:
- -------------------------------------------------------------------------------
At December 31, 1993, there were 2,880,973 outstanding shares of $.75
Convertible Preferred Stock, par value $.01 per share. This stock is
convertible at any time, at the option of the holder, at the rate of 3.5 shares
of Common Stock for each share of $.75 Convertible Preferred Stock, subject to
adjustment upon occurrence of certain events. During 1993, 248,817 shares of
$.75 Convertible Preferred Stock were converted into 870,858 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 $7.50 or higher for at least 20 of the prior 30 trading days, at a
redemption price of $10.50 per share during the twelve-month period which began
July 1, 1993 and declining ratably 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 has paid such dividends in shares of Common Stock.
Thereafter, 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. Common
Stock delivered in payment of dividends will be valued for dividend payment
purposes at between 75% and 90%, based 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. If two consecutive dividend payments are
in arrears, the holders of $.75 Convertible Preferred Stock may exercise a
penalty conversion right during a specified period and may convert shares of
$.75 Convertible Preferred Stock, plus accumulated dividends, to Common Stock at
a conversion price of 75% of the average last reported sales price during a
specified period prior to the conversion date. If six consecutive dividend
payments are in arrears, the holders of the $.75 Convertible Preferred Stock
shall have the right to elect two directors.
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.
In 1985, the Company issued 350,000 shares of $15.75 Cumulative Preferred Stock
(Redeemable Preferred Stock), par value $.01 per share. In February 1990, the
Company issued 2,300,000 shares of $2.125 Convertible Preferred
51
(9) PREFERRED STOCK (cont'd):
- --------------------------------------------------------------------------------
Stock with a par value of $.01 per share and liquidation value of $25 per share.
In December 1991, in connection with the Company's recapitalization, the
Company's shareholders approved an amendment to the Company's Restated
Certificate of Incorporation whereby each share of Redeemable Preferred Stock,
including accumulated dividends, was acquired by the Company for seven shares of
$.75 Convertible Preferred Stock or, at the election of the holder, for $50
principal amount of Senior Secured Notes and 1.2 shares of $.75 Convertible
Preferred Stock and whereby each share of the Company's $2.125 Convertible
Preferred Stock, including accumulated dividends, was reclassified into one
share of $.75 Convertible Preferred Stock. In December 1991, also in connection
with the recapitalization, the Company's shareholders approved an amendment to
the Company's Restated Certificate of Incorporation whereby each share of the
Company's $2.125 Convertible Preferred Stock, including accumulated dividends,
was reclassified into one share of $.75 Convertible Preferred Stock.
(10) COMMON STOCK:
- --------------------------------------------------------------------------------
At December 31, 1993 the Company has one class of Common Stock, par value $.10
per share, which 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.
At the Company's Annual Meeting of Shareholders on May 12, 1993, the
shareholders adopted amendments to the Company's Restated Certificate of
Incorporation to increase the number of authorized shares of Common Stock to
112,000,000 and to reclassify each share of Class B Stock into 1.1 shares of
Common Stock.
On June 15, 1993, the Company issued 11,080,000 shares of Common Stock for $5.00
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.
On October 29, 1993 the Company paid a dividend distribution of one Preferred
Share Purchase Right 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.
The Company has Warrants outstanding which permit holders thereof to purchase
1,244,715 shares of Common Stock at an exercise price of $3.00 per share. The
Warrants are noncallable by the Company and expire on October 1, 1996. The
exercise price is payable in cash.
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.
During 1992 the Company granted options to 42 employees to purchase a total of
1,740,000 shares of Common Stock at an exercise price of $3.00 per share.
During 1993, the Company granted options to 33 employees to purchase a total of
1,525,000 shares of Common Stock at an exercise price of $5.00 per share. The
options vest 20% on the date of grant and an additional 20% on each grant
anniversary date thereafter. The Company may, in its discretion, grant each
optionee a cash bonus upon the exercise of each granted option. At December 31,
1993, there are 1,529,000 options outstanding at an exercise price of $3.00 per
share, of which 776,600 are exercisable, and 1,525,000 options outstanding at
$5.00 per share, of which 525,000 are exercisable.
52
(11) GAS PURCHASE CONTRACT SETTLEMENT:
- --------------------------------------------------------------------------------
On December 17, 1992, the Company and ONEOK, Inc. (ONEOK) agreed to settle the
case styled Forest Oil Corporation v. ONEOK, Inc. (Number 71,582) and its
companion case styled Forest Oil Corporation v. ONEOK, Inc. (Case No. C-89-53).
The cases involved take-or-pay damages relating to a natural gas purchase
contract between the Company and ONEOK. The settlement encompassed all disputed
contracts, claims and future claims. The cash proceeds of $51,250,000 were
received by the Company on December 24, 1992. Proceeds after deducting related
royalties and production taxes were approximately $36,429,000.
The ONEOK settlement increased the Company's net earnings for 1992 by
approximately $24,043,000 or $1.75 per share.
(12) RESTRUCTURING:
- --------------------------------------------------------------------------------
Restructuring expense in 1991 of approximately $3,585,000 related to reductions
in workforce and a consolidation of the Company's technical staff, reduced by a
credit recognized upon curtailment of the Company's defined benefit pension
plan.
(13) EMPLOYEE BENEFITS:
- --------------------------------------------------------------------------------
PENSION PLANS:
The Company has a qualified defined benefit pension plan (Pension Plan). In
1991, in conjunction with its reorganization, the Company effected a curtailment
of the Pension Plan pursuant to which all benefit accruals were suspended
effective May 31, 1991. As a result of the curtailment, the projected benefit
obligation was reduced significantly. Accordingly, the Company recorded a
credit to restructuring expense of $806,000 in accordance with Statement of
Financial Accounting Standards No. 88.
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. The Company's funding policy
has been to contribute annually an amount in excess of the minimum required by
Federal regulations. No contribution was made in 1993, 1992 or 1991. The
following table sets forth the Pension Plan's funded status and amounts
recognized in the Company's consolidated financial statements at December 31:
1993 1992
---- ----
(In Thousands)
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested benefits of
$28,484,000 in 1993 and $23,994,000 in 1992 $(28,484) (23,994)
------- -------
------- -------
Projected benefit obligation for service rendered to date $(28,484) (23,994)
Plan assets at fair market value, consisting primarily of
listed stocks, bonds and other fixed income obligations 25,576 24,431
------- -------
Plan assets in excess of projected benefit obligation (unfunded
pension liability) (2,908) 437
Unrecognized net loss from past experience different from that
assumed and effects of changes in assumptions 3,642 243
------- -------
Pension asset recognized in the balance sheet $ 734 680
------- -------
------- -------
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 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 both 1992 and 1991.
53
(13) EMPLOYEE BENEFITS (cont'd):
- -------------------------------------------------------------------------------
The components of net pension expense (benefit) for the three years ended December 31, are as follows:
1993 1992 1991
---- ---- ----
(In Thousands)
Net pension expense (benefit) included the following components:
Service cost, benefits earned during the period $ - - 239
Interest cost on projected benefit obligation 2,039 2,074 2,153
Actual return on plan assets (3,534) (1,890) (3,705)
Net amortization and deferral 1,441 (240) 952
Net effect of curtailment - - (806)
------ ------ ------
Net pension expense (benefit) $ (54) (56) (1,167)
------- ------ ------
------- ------ ------
In 1990, the Company adopted 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 Company's Pension Plan. At December 31, 1993 the
projected benefit obligation under this plan totaled $493,000, which is included
in other liabilities in the accompanying balance sheet. The projected benefit
obligation is determined using the same discount rate as is used for
calculations for the Pension Plan.
As a result of 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.
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 1993, 1992 and 1991, Company contributions were made using treasury stock.
The expense associated with the Company's contribution was $367,000 in 1993,
$454,000 in 1992 and $492,000 in 1991.
Effective January 1, 1992 the plan was amended to include profit-sharing
contributions by the Company. The Company's profit-sharing contributions were
made using Company stock valued at $276,000 and $465,000 for 1993 and 1992,
respectively.
ANNUAL INCENTIVE PLAN:
The Forest Oil Corporation Annual Incentive Plan (the Incentive Plan), which
became effective January 1, 1992, permits participating employees to earn annual
bonus awards payable in cash or in whole shares of the Company's Common Stock,
generally based in part upon the Company attaining certain levels of
performance. In 1993 and 1992, the Company accrued bonuses of $426,000 and
$930,000, respectively, under the Incentive Plan. Amounts awarded will be
disbursed in equal annual installments over the succeeding three-year period.
EXECUTIVE RETIREMENT AGREEMENTS:
The Company entered into Agreements in December 1990 (the Agreements) with
certain 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 will also continue
to participate in the Company's royalty bonus program until December 31,
54
(13) EMPLOYEE BENEFITS (cont'd):
- -------------------------------------------------------------------------------
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.
Six of the Retirees have subsequently resigned as directors. One of the
Retirees continues to serve as a director and will be paid the customary non-
employee director's fee. Pursuant to the terms of the retirement agreements,
the former directors and any other Retiree who ceases to be a director (or his
spouse) will be paid $2,500 a month until December 2000.
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
($149,000) payable in May 1997. The retirement agreements for the other six
Retirees, one of whom received in 1991 the payments scheduled to be made in 1999
and 2000, provide for supplemental retirement payments totalling approximately
$938,400 per year through 1998 and approximately $740,400 per year in 1999 and
2000.
The present value of the amounts due under the agreements discounted at an
annual rate of 13% has been recorded as retirement benefits payable to
executives and directors.
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 $861,000, $995,000, and $1,534,000 in 1993, 1992
and 1991, respectively, including $766,000, $765,000, and $1,335,000 paid for
policies for retired executives. Under the split dollar life insurance plans,
the Company was assigned a portion of the benefits payable under the policies
which were generally designed to recover the premiums paid by the Company as
well as any bonuses paid to the employees and retirees in connection with the
policies. In December 1991 the Company replaced the existing policies with new,
lower cost policies which provide the same death benefits to the employees and
retirees. The Company is assigned a portion of the benefits which is designed
to recover the premiums paid. As a result of the change in policies, the
Company was able to receive 100% of the cash surrender value of the old
policies, net of outstanding policy loans. The net cash surrender value of
$4,422,000 was received in 1992.
HEALTH AND DENTAL INSURANCE:
The Company provides health and dental insurance to all of its employees,
eligible retirees and eligible dependents. The Company provides these benefits
at nominal cost to employees and retirees and recognizes the expense in the year
incurred. Effective January 1, 1992, the Company replaced its health and dental
plans with new plans which require employees and eligible retirees to contribute
an estimated 50% of the cost of dependent coverage. In 1993, 1992 and 1991 the
costs of providing these benefits for both active and retired employees totalled
$1,350,000, $1,359,000, and $2,111,000, respectively. The 1993 cost includes
$993,110 related to 184 participating active employees and 4 employees on long-
term disability and $356,890 related to 125 eligible retirees. The 1992 cost
includes $1,011,000 related to 183 participating active employees and $348,000
related to 119 eligible retirees. The cost of providing these benefits during
1991 for the 164 eligible retirees are not separable from the costs of providing
these benefits for the 182 participating active employees.
POSTRETIREMENT BENEFITS:
In December 1990, the Financial Accounting Standards Board issued the Statement
of Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions," (SFAS No. 106). This statement
required the Company to accrue expected costs of providing postretirement
benefits to employees, their beneficiaries and covered dependents effective for
fiscal years beginning after December 15, 1992. 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 was approximately $483,000 for 1993.
55
(13) EMPLOYEE BENEFITS (cont'd):
- -------------------------------------------------------------------------------
At January 1 and December 31, 1993 the discount rates used in determining the
actuarial present value of the accumulated postretirement benefit obligation
were 8.5% and 7.5%, respectively.
POSTEMPLOYMENT BENEFITS:
In November 1992, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 112, "Employers' Accounting for
Postemployment Benefits" (SFAS No. 112). This statement requires the accrual of
the estimated cost of certain postemployment benefits provided to former
employees. SFAS No. 112 is effective for years beginning after December 15,
1993. The initial effect of applying this statement is to be accounted for as a
cumulative effect of a change in accounting principle. The Company has not
determined precisely what effect, if any, the adoption of SFAS No. 112 will have
on its financial statements, but believes the effect will be immaterial because
the Company has already recorded liabilities for many of the affected costs.
(14) RELATED PARTY TRANSACTIONS:
- -------------------------------------------------------------------------------
The Company uses 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.
The Company incurred expenses for its use of the Complex of $635,000 in 1993,
$611,000 in 1992, and $691,000 in 1991. The Company has notified the owners
that it intends to terminate its annual usage after 1994, and it will pay
$600,000 for its 1994 usage and $300,000 as a partial reimbursement of deferred
maintenance costs.
John F. Dorn resigned as an executive officer and director of the Company in
1993. The Company has agreed to pay John F. Dorn his salary at time of
resignation through September 30, 1996. In addition, the Company has provided
certain other benefits and services to Mr. Dorn. The present value of the
severance package is 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 for
$4,400,000 to an entity controlled by John F. Dorn and another former executive
officer of the Company. The Company established the sales price based upon an
opinion from an independent third party. The purchasers financed 100% of the
purchase price with a loan bearing interest at the rate of prime plus 1%. The
loan is secured by a mortgage on the properties and personal guarantees of the
purchasers. The Company participated as a lender in the loan in the amount of
approximately $800,000. In addition, the Company agreed to subordinate to the
other lender its right of payment of principal on default. The purchasers have
separately agreed with the Company that certain options to purchase company
stock will be cancelled to the extent that the Company's participation in the
loan is not repaid in full. Collectively, the purchasers have options to
purchase 275,000 shares of the Company's Common Stock at $3.00 per share and
275,000 shares at $5.00 per share.
56
(15) COMMITMENTS AND CONTINGENCIES:
- -------------------------------------------------------------------------------
Future rental payments for office facilities and equipment under the remaining
terms of noncancelable leases are $2,210,000, $1,324,000 and $130,000 for the
years ending December 31, 1994, 1995 and 1996, respectively.
Net rental payments applicable to exploration and development activities and
capitalized in the oil and gas property accounts aggregated $688,000 in 1993,
$874,000 in 1992 and $1,562,000 in 1991. Net rental payments charged to expense
amounted to $3,098,000 in 1993, $3,112,000 in 1992 and $2,748,000 in 1991.
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
financial condition of the Company.
(16) FINANCIAL INSTRUMENTS:
- -------------------------------------------------------------------------------
Statement of Financial Accounting Standards No. 105 requires certain disclosures
about financial instruments with off-balance-sheet risk. 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. 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. The
following table indicates outstanding energy swaps of the Company which were in
place at December 31, 1993:
Fixed
Product Volume Price Duration
------- ------ ----- --------
Natural Gas 5,000 MMBTU/day 1.945 1/94-12/94
Natural Gas 1,368 to 2,751 MMBTU/day 2.0275 1/94-12/94
Natural Gas 5,000 MMBTU/day 2.300 1/94-12/94
Natural Gas 850 to 1,377 MMBTU/day 2.255 1/95-9/95
Natural Gas 194 to 17,1000 MMBTU/day 1.955-2.535 1/94-12/99
Under another agreement (the Option Agreement), the Company paid a premium of
$516,000 in conjunction with the closing of the Enron loan agreement. The
payment of this premium gives Forest the right to set a floor price of $1.70 per
MMBTU on a total of 18.4 BBTU of natural gas over a five year period commencing
January 1, 1995. In order to exercise this right to set a floor, the Company
must pay an additional premium of 10 cents per MMBTU, effectively setting the
floor at $1.60 per MMBTU. The premium of $516,000 related to the Option
Agreement was recorded as a long-term asset and will be amortized as a
reduction to oil and gas income beginning in 1995 based on the volumes
involved.
In December 1991, the Financial Accounting Standards Board issued Statement 107,
"Disclosures about Fair Value of Financial Instruments." The statement requires
disclosure of the estimated fair value of certain on and off-balance sheet
financial instruments in the financial statements. The following methods and
assumptions were used to estimate the fair value of the Company's financial
instruments as of December 31, 1993:
CASH AND CASH EQUIVALENTS, ACCOUNTS RECEIVABLES AND ACCOUNTS PAYABLE:
The carrying amount of these instruments approximates fair value because of
their short maturity.
57
(16) FINANCIAL INSTRUMENTS (cont'd):
- --------------------------------------------------------------------------------
PRODUCTION PAYMENT OBLIGATION:
The fair value of the Company's production payment obligation has been estimated
as approximately $20,433,000 by discounting the projected future cash payments
required under the agreement by 12.5%. This rate corresponds to the rate on the
Company's recent nonrecourse loan agreement.
SENIOR SUBORDINATED NOTES
The fair value of the Company's 11 1/4% Subordinated Notes was approximately
$112,179,000, based upon quoted market prices for the same or similar issues.
ENERGY SWAP AGREEMENTS:
The fair value of the Company's energy swap agreements was approximately
$508,000, based upon the estimated net amount the Company would receive to
terminate the agreements.
(17) 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:
1993 1992 1991
---- ---- ----
(In Thousands)
Enron Affiliates (A) $63,075 12,646 11,836
ONEOK Exploration Company (B) - 22,392 -
KNEnergy, Inc. - - 7,338
(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, and Enron Reserve Acquisition. Approximately
$32,702,000, $14,081,000 and $8,979,000 represent sales recorded for
deliveries under volumetric production payments in the years ended December
31, 1993, 1992 and 1991, respectively.
(B) The amount shown for ONEOK Exploration Company represents the amount
recorded as a result of the gas purchase contract settlement described in
Note 11.
58
(18) SELECTED QUARTERLY FINANCIAL DATA (unaudited):
- --------------------------------------------------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
(In Thousands Except Per Share Amounts)
1993
- ----
Revenue $ 25,126 27,975 26,214 25,833
------ ------ ------ ------
Net loss $ (2,389) (938) (13,102) (4,784)
------ ------ ------ ------
Net loss attributable to $ (2,976) (1,508) (13,653) (5,326)
common stock ------ ------ ------ ------
Primary loss per share $ (.20) (.09) (.50) (.19)
------ ------ ------ ------
Fully diluted loss per $ (.20) (.09) (.50) (.19)
share ------ ------ ------ ------
1992
- ----
Revenue $ 17,294 16,960 21,768 57,164 (A)
------ ------ ------ ------
Net earnings (loss) $ (4,513) (4,993) (1,897) 18,701 (B)
------ ------ ------ ------
Net earnings (loss)
attributable to common $ (5,100) (5,580) (2,484) 18,114 (B)
stock ------ ------ ------ ------
Primary earnings (loss) $ (.40) (.41) (.18) 1.25 (B)
per share ------ ------ ------ ------
Fully diluted earnings $ (.40) (.41) (.18) .69 (B)
(loss) per share ------ ------ ------ ------
(A) Includes $37,541,000 attributable to the ONEOK settlement.
(B) Includes $24,043,000 or $1.66 per share attributable to the ONEOK
settlement.
59
(19) 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).
(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 three years ended December 31, 1993:
UNITED
STATES CANADA TOTAL
------ ------ -----
(In Thousands)
1993
- ----
PROPERTY ACQUISITION COSTS
(UNDEVELOPED LEASES AND PROVED
PROPERTIES) $ 144,247 669 144,916
EXPLORATION COSTS 5,433 - 5,433
DEVELOPMENT COSTS 20,472 - 20,472
------- ------ -------
TOTAL $ 170,152 669 170,821
------- ------ -------
------- ------ -------
1992
- ----
Property acquisition costs
(undeveloped leases and proved
properties) $ 88,770 2 88,772
Exploration costs 2,171 126 2,297
Development costs 14,828 730 15,558
------- ------ -------
Total $ 105,769 858 106,627
------- ------ -------
------- ------ -------
1991
- ----
Property acquisition costs
(proved properties) $ 13,013 547 13,560
Exploration costs 8,556 1,167 9,723
Development costs 10,715 1,666 12,381
------- ------ -------
Total $ 32,284 3,380 35,664
------- ------ -------
------- ------ -------
(B) AGGREGATE CAPITALIZED COSTS - The aggregate capitalized costs relating to
oil and gas activities were incurred as of the date indicated:
DECEMBER 31,
1993 1992
---- -----
(In Thousands)
Costs related to proved properties $ 1,079,164 928,890
Costs related to unproved properties:
Costs subject to depletion (including
wells in progress) 20,276 24,785
Costs not subject to depletion 41,216 18,306
--------- -------
1,140,656 971,981
Less accumulated depletion and
valuation allowance 778,226 717,444
--------- -------
$ 362,430 254,537
--------- -------
--------- -------
60
(19) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES
(unaudited) (cont'd)
- --------------------------------------------------------------------------------
(C) RESULTS OF OPERATIONS FROM PRODUCING ACTIVITIES - Results of operations
from producing activities for 1993, 1992 and 1991 are presented below. Income
taxes are different from income taxes shown in the Consolidated Statements of
Operations because this table excludes general and administrative and interest
expense.
UNITED
STATES CANADA TOTAL
------ ------ -----
(In Thousands)
1993
----
Oil and gas sales $ 102,883 - 102,883
Production expense 19,540 - 19,540
Depletion expense 59,759 - 59,759
Income tax expense 8,141 - 8,141
------- ------ -------
87,440 - 87,440
------- ------ -------
Results of operations from producing activities $ 15,443 - 15,443
------- ------ -------
------- ------ -------
1992
----
Oil and gas sales $ 94,289 (A) 4,950 99,239 (A)
Production expense 14,516 (B) 1,349 15,865 (B)
Depletion expense 43,052 2,625 45,677
Income tax expense 12,615 332 12,947
------ ------ ------
70,183 4,306 74,489
------ ------ ------
Results of operations from producing activities $ 24,106 644 24,750
------ ------ ------
------ ------ ------
1991
----
Oil and gas sales $ 61,166 7,710 68,876
Production expense 10,874 1,674 12,548
Depletion expense 33,668 3,594 37,262
Provision for impairment of oil and
gas properties 15,000 19,000 34,000
Income tax expense (benefit) 525 (5,630) (5,105)
------ ------ ------
60,067 18,638 78,705
------ ------ ------
Results of operations from producing activities $ 1,099 (10,928) (9,829)
------ ------ ------
------ ------ ------
(A)Includes $22,392,000 attributable to the ONEOK settlement.
(B)Includes $1,589,000 attributable to the ONEOK settlement.
61
(19) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (unaudited)
(cont'd):
- --------------------------------------------------------------------------------
(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 1991, 1992 and 1993 follows. Such estimates are inherently
imprecise and may be subject to substantial revisions.
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 16), but not on escalations based on future
conditions. The Company has decreased these quantities for overproduced volumes
recognized as revenue, as discussed in Note 1. The reserve volumes include
quantities subject to volumetric production payments discussed in Note 7.
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.
OIL AND CONDENSATE GAS
-------------------------------- --------------------------------
(MBBLS) (MMCF)
United United
States Canada Total States Canada Total
------ ------ ----- ------ ------ -----
Balance at December 31, 1990 4,175 2,384 6,559 178,605 26,408 205,013
Revisions of previous estimates (417) (160) (577) (2,808) (1,296) (4,104)
Extensions and discoveries 79 - 79 4,164 - 4,164
Production (637) (210) (847) (22,517) (1,360) (23,877)
Sale of reserves in place (365) - (365) (10,684) - (10,684)
Purchases of reserves in place 296 170 466 22,959 - 22,959
----- ----- ----- ------- ------ -------
Balance at December 31, 1991 3,131 2,184 5,315 169,719 23,752 193,471
Revisions of previous estimates (139) 33 (106) (9,837) (219) (10,056)
Extensions and discoveries 9 - 9 1,127 - 1,127
Production (1,308) (142) (1,450) (27,814) (1,360) (29,174)
Sale of reserves in place - (2,075) (2,075) (1,883) (22,173) (24,056)
Purchases of reserves in place 5,867 - 5,867 63,343 - 63,343
----- ----- ----- ------- ------ -------
Balance at December 31, 1992 7,560 - 7,560 194,655 - 194,655
Revisions of previous estimates 507 - 507 17,874 - 17,874
Extensions and discoveries 201 - 201 8,395 - 8,395
Production (1,493) - (1,493) (41,114) - (41,114)
Sales of reserves in place (281) - (281) (1,158) - (1,158)
Purchases of reserves in place 1,704 - 1,704 94,730 - 94,730
----- ----- ----- ------- ------ -------
Balance at December 31, 1993 8,198 - 8,198 273,382 - 273,382
----- ----- ----- ------- ------ -------
----- ----- ----- ------- ------ -------
Purchases of reserves in place represent volumes recorded on the closing dates
of the acquisitions for financial accounting purposes.
62
(19) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (unaudited)
(cont'd):
- --------------------------------------------------------------------------------
(D) ESTIMATED PROVED OIL AND GAS RESERVES (cont'd)
OIL AND CONDENSATE GAS
----------------------- -----------------------
(MBBLS) (MMCF)
UNITED UNITED
STATES CANADA TOTAL STATES CANADA TOTAL
------ ------ ----- ------ ------ -----
Proved developed reserves:
Balance at:
December 31, 1990 3,509 2,147 5,656 151,576 22,592 174,168
December 31, 1991 2,903 1,824 4,727 153,395 20,807 174,202
December 31, 1992 6,418 - 6,418 176,282 - 176,282
December 31, 1993 6,778 - 6,778 216,820 - 216,820
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS - The standardized
measure of discounted net cash flows is calculated in accordance with the
provisions of SFAS No. 69.
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. 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. Prior to December 31, 1993 the
contracts included natural gas sales contracts with a Company which is involved
in Chapter 11 bankruptcy proceedings. At December 31, 1993 the volumes
applicable to this contract were priced at spot prices. Future oil and gas
sales include the estimated effects of existing energy swap agreements and the
volumetric production payments, as discussed in Notes 7 and 16, and have been
reduced for overproduced volumes recognized as revenue, as discussed in Note 1.
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.
UNITED STATES
DECEMBER 31,
---------------------------
1993 1992
---- ----
(In Thousands)
Future oil and gas sales $ 716,663 549,643
Future production and development costs (254,407) (200,432)
------- -------
Future net revenue 462,256 349,211
10% annual discount for estimated timing of cash flows (138,917) (103,636)
------- -------
Present value of future net cash flows before income taxes 323,339 245,575
Present value of future income tax expense (24,286) (18,566)
------- -------
Standardized measure of discounted future net cash flows $ 299,053 227,009
------- -------
------- -------
Undiscounted future income tax expense in the United States was $35,028,000 at
December 31, 1993 and $32,718,000 at December 31, 1992.
63
(19) SUPPLEMENTAL FINANCIAL DATA - OIL AND GAS PRODUCING ACTIVITIES (unaudited)
(cont'd):
- --------------------------------------------------------------------------------
(E) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (cont'd)
United
States Canada Total
------ ------ -----
(In Thousands)
December 31, 1991
Future oil and gas sales $ 388,497 82,008 470,505
Future production and development costs (138,887) (24,692) (163,579)
------- ------ -------
Future net revenue 249,610 57,316 306,926
Future income tax expense (20,704) (2,856) (23,560)
------- ------ -------
Future net cash flows 228,906 54,460 283,366
10% annual discount for estimated timing of cash flows (71,256) (24,041) (95,297)
------- ------ -------
Standardized measure of discounted future net cash flows $ 157,650 30,419 188,069
------- ------ -------
------- ------ -------
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING
TO PROVED OIL AND GAS RESERVES - An analysis of the decrease during each of the
last three years of the total standardized measure of discounted future net cash
flows is as follows:
1993 1992 1991
---- ---- ----
(In Thousands)
Beginning of year $ 227,009 188,069 241,303
Changes resulting from:
Sales of oil and gas, net of production costs (83,343) (62,572) (56,329)
Net changes in prices and future production costs (23,189) 15,076 (69,078)
Net changes in future development costs (18,724) (2,444) 2,451
Extensions, discoveries and improved recovery 15,322 2,122 4,165
Previously estimated development costs incurred during the period 13,424 9,315 7,180
Revisions of previous quantity estimates 25,262 (11,450) (10,305)
Sales of reserves in place (2,964) (42,354) (12,167)
Purchases of reserves in place 127,418 113,567 30,628
Accretion of discount on reserves at beginning of year before
income taxes 24,558 20,392 27,944
Net change in income taxes (5,720) (2,712) 22,277
------- ------- -------
End of year $ 299,053 227,009 188,069
------- ------- -------
------- ------- -------
64
PART III
For information concerning Item 10 - Directors and Executive Officers of the
Registrant, Item 11 - Executive Compensation, Item 12 - Security Ownership of
Certain Beneficial Owners and Management and Item 13 - Certain Relationships and
Related Transactions, see the definitive Proxy Statement of Forest Oil
Corporation relative to the Annual Meeting of Shareholders to be held on May 11,
1994, which will be filed with the Securities and Exchange Commission, which
information is incorporated herein by reference. For information concerning
Item 10 - Executive Officers of Registrant, see Part I - Item 4A.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a).(1) FINANCIAL STATEMENTS
1. Independent Auditors' Report
2. Consolidated Balance Sheets - December 31, 1993 and 1992
3. Consolidated Statements of Operations - Years ended December 31,
1993, 1992 and 1991
4. Consolidated Statements of Shareholders' Equity - Years ended
December 31, 1993, 1992 and 1991
5. Consolidated Statements of Cash Flows - Years ended December 31,
1993, 1992 and 1991
6. Notes to Consolidated Financial Statements - Years ended December 31,
1993, 1992 and 1991
(2) FINANCIAL STATEMENT SCHEDULES
1. Independent Auditors' Report
2. Schedule V: Property and Equipment - Years ended December 31, 1993,
1992 and 1991
3. Schedule VI: Accumulated Depreciation, Depletion and Valuation
Allowance of Property and Equipment - Years ended December 31,
1993, 1992 and 1991
4. Schedule X: Supplementary Operating Statement Information - Years
ended December 31, 1993, 1992 and 1991
Financial statement schedules omitted:
All other 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 Building, Bradford,
Pennsylvania 16701, provide copies of each of the following Exhibits:
65
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(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.
*Exhibit 3(ii)(b) Amendment No. 8 to By-Laws dated as of February 24, 1994.
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 Credit Agreement dated as of December 1, 1993 between Forest Oil
Corporation and Subsidiary Borrowers and Subsidiary Guarantors and The Chase
Manhattan Bank (National Association), as agent.
*Exhibit 4.3 Amendment No. 1 dated as of December 28, 1993 relating to
Exhibit 4.2 hereof.
*Exhibit 4.4 Amendment No. 2 dated as of January 27, 1994 relating to Exhibit
4.2 hereof.
*Exhibit 4.5 Security Agreement dated as of December 1, 1993 between Forest
Oil Corporation and The Chase Manhattan Bank (National Association), as agent.
*Exhibit 4.6 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 4.7 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 4.8 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 4.9 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 4.10 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 4.11 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).
66
No other instruments regarding long-term debt are filed because the amount of
the securities authorized thereunder do not, in any case, exceed 10% of the
total assets of Forest Oil Corporation on a consolidated basis, but a copy of
such instruments will be furnished to the Commission upon request.
+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 Deferred Compensation Agreement,
incorporated herein by reference to Exhibit 10.3 to Form 10-K for Forest Oil
Corporation for the year 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 hereof, 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.
*+Exhibit 10.10 Form of Settlement Agreement and General Release between John F.
Dorn and Forest Oil Corporation dated March 7, 1994.
*Exhibit 11 Forest Oil Corporation and Subsidiaries - Calculation of
Earnings per Share of Common Stock.
*Exhibit 24 Independent Auditors' Consent.
*Exhibit 25 Powers of Attorney of the following Officers and
Directors:
Donald H. Anderson, Austin M. Beutner, Robert S. Boswell, Richard J.
Callahan, Dale F. Dorn, John C. Dorn, William L. Dorn, Harold D.
Hammar, David H. Keyte, James H. Lee, Daniel L. McNamara, Jeffrey W.
Miller, Jack D. Riggs and Michael B. Yanney.
**Exhibit 28 Form 11-K of the Thrift Plan of Forest Oil
Corporation for the year ended December 31, 1993.
* Filed with this report.
**To be filed by amendment.
+ Management contract or compensatory plan or arrangement required to be
filed as an exhibit to this Form 10-K pursuant to Item 14(c) of this report.
67
(b). REPORTS ON FORM 8-K
The following reports on Form 8-K were filed by Forest during the last
quarter of 1993:
Date of Report Item Reported Financial Statements Filed
-------------- ------------- --------------------------
October 14, 1993 Items 5 and 7 None
December 17, 1993 Items 5 and 7 None
December 30, 1993 Items 2 and 7 None
68
SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned thereunto duly authorized.
FOREST OIL CORPORATION
(Registrant)
Date: March 28, 1994 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
---------- ----- ----
William L. Dorn* Chairman of the Board and March 28, 1994
(William L. Dorn) Chief Executive Officer
(Principal Executive Officer)
Robert S. Boswell* President and Chief Financial Officer March 28, 1994
(Robert S. Boswell) (Principal Financial Officer)
David H. Keyte* Vice President and Chief Accounting March 28, 1994
(David H. Keyte) Officer
(Principal Accounting Officer)
Donald H. Anderson*
(Donald H. Anderson)
Austin M. Beutner*
(Austin M. Beutner)
Robert S. Boswell*
(Robert S. Boswell)
Directors of the Registrant March 28, 1994
Richard J. Callahan*
(Richard J. Callahan)
Dale F. Dorn*
(Dale F. Dorn)
John C. Dorn*
(John C. Dorn)
69
SIGNATURES TITLE DATE
---------- ----- ----
William L. Dorn*
(William L. Dorn)
Harold D. Hammar*
(Harold D. Hammar)
James H. Lee*
(James H. Lee)
Directors of the Registrant March 28, 1994
Jeffrey W. Miller*
(Jeffrey W. Miller)
Jack D. Riggs*
(Jack D. Riggs)
Michael B. Yanney*
(Michael B. Yanney)
*By /s/ Daniel L. McNamara March 28, 1994
-----------------------------
Daniel L. McNamara
(as attorney-in-fact for
each of the persons indicated)
70
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders
Forest Oil Corporation:
Under date of February 22, 1994, we reported on the consolidated balance sheets
of Forest Oil Corporation and subsidaries as of December 31, 1993 and 1992, 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,
1993, as contained in the annual report on Form 10-K for the year 1993. In
connection with our audits of the aforementioned consolidated financial
statements, we have also audited the related financial statement schedules V,
VI, and X. These financial statement schedules are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statement schedules based on our audit.
In our opinion, the related financial statement schedules, when considered in
relation to the basic consolidated financial statements taken as a whole,
present fairly, in all material respects, the information set forth therein.
As discussed in Notes 8 and 13 to the financial statements, the Company changed
its method of accounting for income taxes and postretirement benefits.
KPMG PEAT MARWICK
Denver, Colorado
February 22, 1994
SCHEDULE V
FOREST OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
Property and Equipment
Years ended December 31, 1993, 1992 and 1990
(In Thousands)
Balance at Other Balance
beginning Additions changes at end
Classification of period at cost Retirements (A) of period
------------------- ----------- --------- ----------- ------- ---------
Year ended December 31, 1993:
Oil and gas properties $ 971,981 170,821 2,146 - 1,140,656
Land and buildings 2,413 17 402 - 2,028
Transportation equipment 115 - 45 - 70
Furniture and fixtures 7,957 327 10 - 8,274
Other 2,047 1 - - 2,048
---------- ------- ----- ------ ---------
$ 984,513 171,166 2,603 - 1,153,076
---------- ------- ----- ------ ---------
---------- ------- ----- ------ ---------
Year ended December 31, 1992:
Oil and gas properties $ 993,781 106,627 128,427 - 971,981
Land and buildings 2,013 400 - - 2,413
Transportation equipment 142 194 221 - 115
Furniture and fixtures 8,368 138 549 - 7,957
Other 3,753 66 1,772 - 2,047
---------- ------- ----- ------ ---------
$1,008,057 107,425 130,969 - 984,513
---------- ------- ----- ------ ---------
---------- ------- ----- ------ ---------
Year ended December 31, 1991:
Oil and gas properties $1,024,392 35,664 66,703 428 993,781
Land and buildings 2,014 - 1 - 2,013
Transportation equipment 274 19 156 5 142
Furniture and fixtures 7,675 713 11 (9) 8,368
Other 3,929 53 230 1 3,753
---------- ------- ----- ------ ---------
$1,038,284 36,449 67,101 425 1,008,057
---------- ------- ----- ------ ---------
---------- ------- ----- ------ ---------
(A) Foreign currency translation.
SCHEDULE VI
FOREST OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
Accumulated Depreciation, Depletion and Valuation Allowance
of Property and Equipment
Years ended December 31, 1993, 1992 and 1991
(In Thousands)
Additions
Balance at charged to Other Balance
Beginning costs and changes at end
Description of period expenses(A) Retirements (B) of period
------------- ---------- ----------- ------------ ------- ---------
Year ended December 31, 1993:
Oil and gas properties $ 717,444 59,900 (882) - 778,226
Land and buildings 122 10 13 - 119
Transportation equipment 14 13 4 - 23
Furniture and fixtures 6,360 641 5 - 6,996
Other 1,999 17 - - 2,016
---------- ------ ------ ----- -------
$ 725,939 60,581 (860) - 787,380
---------- ------ ------ ----- -------
---------- ------ ------ ----- -------
Year ended December 31, 1992:
Oil and gas properties $ 754,768 45,716 83,040 - 717,444
Land and buildings 100 22 - - 122
Transportation equipment 78 20 84 - 14
Furniture and fixtures 5,952 800 392 - 6,360
Other 3,477 66 1,544 - 1,999
---------- ------ ------ ----- -------
$ 764,375 46,624 85,060 - 725,939
---------- ------ ------ ----- -------
---------- ------ ------ ----- -------
Year ended December 31, 1991:
Oil and gas properties $ 734,536 71,262 51,045 15 754,768
Land and buildings 91 9 - - 100
Transportation equipment 123 16 65 4 78
Furniture and fixtures 5,185 808 50 9 5,952
Other 3,429 134 87 1 3,477
$ 743,364 72,229 51,247 29 764,375
---------- ------ ------ ----- -------
---------- ------ ------ ----- -------
(A) Includes a $15,000,000 valuation allowance related to the U.S. full cost pool, and a $19,000,000 valuation allowance related to
the Canadian full cost pool for 1991.
(B) Foreign currency translation.
SCHEDULE X
FOREST OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
Supplementary Income Statement Information
Years ended December 31, 1993, 1992 and 1991
CHARGED TO COSTS AND EXPENSES
---------------------------------------
1993 1992 1991
---- ---- ----
(In Thousands)
Taxes, other than payroll and Federal
income taxes:
Production $ 1,373 3,031 (1) 1,725
Ad valorem 629 377 320
State franchise and other 189 137 (49)
---------- ------ ------
Total taxes $ 2,191 3,545 1,996
---------- ------ ------
---------- ------ ------
(1) Includes $1,589,000 related to the ONEOK settlement described in Note 11 of Notes to Consolidated Financial Statements.
Other supplementary income statement information required by Rule 12-11 is not
presented because the required item does not exceed 1 percent of total sales and
revenues reported in the related income statement, except for maintenance and
repair costs included in the Company's oil and gas production expense. Such
maintenance and repair costs cannot be distinguished from other components of
lease operating expense.