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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