<PAGE>
- -------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from N/A to N/A
Commission File Number 0-4597
FOREST OIL CORPORATION
(Exact name of registrant as specified in its charter)
New York 25-0484900
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
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
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.
Yes X No
------ ------
NUMBER OF SHARES
OUTSTANDING
TITLE OF CLASS OF COMMON STOCK OCTOBER 31, 1994
- ------------------------------ ----------------
Common Stock, Par Value $.10 Per Share 28,157,088
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<PAGE>
PART I. FINANCIAL INFORMATION
FOREST OIL CORPORATION
Condensed Consolidated Balance Sheets
(Unaudited)
<TABLE>
<CAPTION>
September 30, December 31,
1994 1993
----------- ----------
(In Thousands)
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents $ 2,027 6,949
Accounts receivable 22,918 25,257
Other current assets 2,656 3,309
---------- ----------
Total current assets 27,601 35,515
Property and equipment, at cost:
Oil and gas properties - full cost accounting method 1,159,862 1,140,656
Buildings, transportation and other equipment 12,569 12,420
---------- ----------
1,172,431 1,153,076
Less accumulated depreciation, depletion and valuation allowance 870,100 787,380
---------- ----------
Net property and equipment 302,331 365,696
Investment in and advances to affiliate 11,731 16,451
Other assets 10,911 9,093
---------- ----------
$ 352,574 426,755
---------- ----------
---------- ----------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Cash overdraft $ 3,464 3,894
Current portion of nonrecourse secured loan and production payment obligation 686 4,371
Current portion of subordinated debentures -- 7,171
Accounts payable 21,503 28,348
Retirement benefits payable to executives and directors 610 553
Accrued expenses and other liabilities:
Interest 1,616 3,817
Other 4,483 1,857
---------- ----------
Total current liabilities 32,362 50,011
Long-term bank debt 27,000 25,000
Nonrecourse secured loan and production payment obligation 74,606 70,035
Subordinated debentures 99,305 99,272
Retirement benefits payable to executives and directors 3,623 4,135
Other liabilities 20,657 22,918
Deferred revenue 43,791 67,228
Shareholders' equity:
Convertible preferred stock 15,845 15,845
Capital stock 2,829 2,825
Capital surplus 189,594 193,717
Accumulated deficit (153,548) (117,656)
Foreign currency translation (914) (785)
Treasury stock (2,576) (5,790)
---------- ----------
Total shareholders' equity 51,230 88,156
---------- ----------
$ 352,574 426,755
---------- ----------
---------- ----------
</TABLE>
See accompanying notes to condensed consolidated financial statements.
-1-
<PAGE>
FOREST OIL CORPORATION
Condensed Consolidated Statements of Production and Operations
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
---------------------------- ------------------------------
September 30, September 30, September 30, September 30,
1994 1993 1994 1993
------------- ------------- ------------- -------------
(In Thousands Except Production and Per Share Amounts)
<S> <C> <C> <C> <C>
PRODUCTION
Gas (MMCF) 11,371 10,719 36,628 30,416
--------- --------- --------- ---------
--------- --------- --------- ---------
Oil and condensate (thousand barrels) 365 369 1,152 1,146
--------- --------- --------- ---------
--------- --------- --------- ---------
STATEMENTS OF CONSOLIDATED OPERATIONS:
Revenue:
Oil and gas sales:
Gas $ 20,727 19,943 70,483 57,933
Oil and condensate 5,830 5,811 16,825 19,665
Products and other 66 -- 280 --
--------- --------- --------- ---------
26,623 25,754 87,588 77,598
Miscellaneous, net 437 460 2,299 1,717
--------- --------- --------- ---------
Total revenue 27,060 26,214 89,887 79,315
Expenses:
Oil and gas production 5,419 4,897 16,647 13,789
General and administrative 2,964 2,582 7,553 7,556
Interest 6,602 5,753 20,077 19,068
Depreciation and depletion 15,869 15,734 51,473 44,730
Provision for impairment of oil and gas properties 30,000 -- 30,000 --
--------- --------- --------- ---------
Total expenses 60,854 28,966 125,750 85,143
--------- --------- --------- ---------
Loss before income taxes, cumulative effects of
changes in accounting principles and extraordinary
loss on extinguishment of debt (33,794) (2,752) (35,863) (5,828)
Income tax expense (benefit):
Current (55) (172) 29 254
Deferred -- (227) -- (1,525)
--------- --------- --------- ---------
(55) (399) 29 (1,271)
--------- --------- --------- ---------
Loss before cumulative effects of changes in
accounting principles and extraordinary
loss on extinguishment of debt (33,739) (2,353) (35,892) (4,557)
Cumulative effects of changes in accounting principles:
Postretirement benefits, net of income tax
benefit of $1,639,000 -- -- -- (3,183)
Income taxes -- -- -- 2,060
--------- --------- --------- ---------
-- -- -- (1,123)
--------- --------- --------- ---------
Loss before extraordinary loss on
extinguishment of debt (33,739) (2,353) (35,892) (5,680)
Extraordinary loss on extinguishment of debt, net
of tax benefit of $4,652,000 -- (10,749) -- (10,749)
--------- --------- --------- ---------
Net loss $ (33,739) (13,102) (35,892) (16,429)
--------- --------- --------- ---------
--------- --------- --------- ---------
</TABLE>
(continued on next page)
-2-
<PAGE>
FOREST OIL CORPORATION
Condensed Consolidated Statements of Production and Operations, continued
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
---------------------------- ------------------------------
September 30, September 30, September 30, September 30,
1994 1993 1994 1993
------------- ------------ ------------- -------------
(In Thousands Except Production and Per Share Amounts)
<S> <C> <C> <C> <C>
Weighted average number of common shares
outstanding 28,135 27,525 28,072 20,032
--------- --------- --------- ---------
--------- --------- --------- ---------
Net loss attributable to common stock $ (34,280) (13,653) (37,513) (18,137)
--------- --------- --------- ---------
--------- --------- --------- ---------
Primary and fully diluted loss per share:
Loss before cumulative effects of changes in
accounting principles and extraordinary
loss on extinguishment of debt $ (1.20) (.09) (1.28) (.23)
Cumulative effects of changes in
accounting principles -- -- -- (.06)
--------- --------- --------- ---------
Loss before extraordinary loss on
extinguishment of debt (1.20) (.09) (1.28) (.29)
--------- --------- --------- ---------
Extraordinary loss on extinguishment of debt -- (.39) -- (.53)
--------- --------- --------- ---------
Net loss $ (1.20) (.48) (1.28) (.82)
--------- --------- --------- ---------
--------- --------- --------- ---------
Net loss attributable to common stock $ (1.22) (.50) (1.34) (.91)
--------- --------- --------- ---------
--------- --------- --------- ---------
</TABLE>
See accompanying notes to condensed consolidated financial statements.
-3-
<PAGE>
FOREST OIL CORPORATION
Condensed Consolidated Statements of Cash Flows
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
-----------------------------
September 30, September 30,
1994 1993
-------------- -------------
(In Thousands)
<S> <C> <C>
Cash flows from operating activities:
Loss before cumulative effects of changes in accounting principles
and extraordinary loss on extinguishment of debt $ (35,892) (4,557)
Adjustments to reconcile loss to net cash provided by operating activities:
Depreciation and depletion 51,473 44,730
Provision for impairment of oil and gas properties 30,000 --
Deferred Federal income tax benefit -- (1,525)
Other, net 3,230 2,526
---------- ----------
48,811 41,174
Net changes in current assets and liabilities:
Decrease in accounts receivable 2,339 3,913
(Increase) decrease in other current assets 653 (844)
Decrease in accounts payable (6,788) (16,890)
Increase (decrease) in accrued expenses and other liabilities 425 (1,856)
---------- ----------
Net cash provided by operating activities 45,440 25,497
Cash flows from investing activities:
Capital expenditures for property and equipment (26,706) (45,960)
Proceeds from sales of property and equipment 13,203 2,726
Increase in other assets, net (1,895) (1,914)
---------- ----------
Net cash used by investing activities (15,398) (45,148)
Cash flows from financing activities:
Proceeds of long-term bank debt 12,500 --
Repayments of long-term bank debt (10,500) --
Proceeds of nonrecourse secured loan 1,400 --
Repayments of production payment (2,394) (4,930)
Redemptions and purchases of subordinated debentures (7,171) (33,094)
Proceeds of volumetric production payments 4,353 27,261
Amortization of deferred revenue (27,790) (29,436)
Proceeds of common stock offering, net of offering costs -- 51,506
Issuance of senior subordinated notes, net of offering costs -- 96,259
Preferred stock dividends (1,621) --
Deferred debt costs (702) (113)
Decrease in cash overdraft (430) (2,575)
Decrease in other liabilities, net (2,773) (687)
---------- ----------
Net cash provided (used) by financing activities (35,128) 104,191
Effect of exchange rate changes on cash 164 --
---------- ----------
Net increase (decrease) in cash and cash equivalents (4,922) 84,540
Cash and cash equivalents at beginning of period 6,949 63,487
---------- ----------
Cash and cash equivalents at end of period $ 2,027 148,027
---------- ----------
---------- ----------
Cash paid during the period for:
Interest $ 20,543 19,330
---------- ----------
---------- ----------
Income taxes $ 6 453
---------- ----------
---------- ----------
</TABLE>
See accompanying notes to condensed consolidated financial statements.
-4-
<PAGE>
FOREST OIL CORPORATION
Notes to Condensed Consolidated Financial Statements
Nine Months Ended September 30, 1994 and 1993
(Unaudited)
(1) Basis of Presentation
The consolidated financial statements included herein are unaudited. In
the opinion of management, all adjustments, consisting of normal recurring
accruals, have been made which are necessary for a fair presentation of the
financial position of the Company at September 30, 1994 and the results of
operations for the nine month periods ended September 30, 1994 and 1993.
Quarterly results are not necessarily indicative of expected annual results
because of the impact of fluctuations in prices received for oil and
natural gas and other factors. For a more complete understanding of the
Company's operations and financial position, reference is made to the
consolidated financial statements of the Company, and related notes
thereto, filed with the Company's annual report on Form 10-K for the year
ended December 31, 1993, previously filed with the Securities and Exchange
Commission.
(2) Earnings (Loss) Per Share
Primary earnings (loss) per share is computed by dividing net earnings
(loss) attributable to common stock by the weighted average number of
common shares and common share equivalents outstanding during each period,
excluding treasury shares. Net earnings (loss) attributable to common
stock represents net earnings (loss) less preferred stock dividend
requirements. Common share equivalents include, when applicable, dilutive
stock options using the treasury stock method and warrants using the if
converted method.
Fully diluted earnings (loss) per share is computed assuming, in addition
to the above, (i) that convertible debentures were converted at the
beginning of each period or date of issuance, if later, with earnings being
increased for interest expense, net of taxes, that would not have been
incurred had conversion taken place, (ii) that convertible preferred stock
was converted at the beginning of each period or date of issuance, if
later, and (iii) any additional dilutive effect of stock options and
warrants. The assumed exercises and conversions were antidilutive for the
nine months ended September 30, 1994 and 1993.
(3) Acquisitions
The Company completed three significant property acquisitions in the fourth
quarter of 1993. The results of operations of the Company for the 1994
periods presented herein include the effects of those acquisitions.
(4) Investment in and Advances to Affiliate
On June 24, 1994 the Company's affiliate, CanEagle Resources Corporation
(CanEagle), sold a significant portion of its oil and gas properties in
Canada to a third party. In conjunction with this transaction, the Company
received payment of approximately $4,400,000 ($6,124,000 CDN) representing
principal and unpaid interest on the CanEagle subordinated debenture held
by the Company. In addition, the Company exchanged its remaining
investment in CanEagle for preferred shares of a newly formed entity,
Archean Energy, Ltd. The Company recognized no gain or loss as a result of
this transaction.
-5-
<PAGE>
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 FOR THE THIRD QUARTER OF 1994
NET LOSS
The net loss for the third quarter of 1994 was $33,739,000 or $1.22 per
common share compared to a net loss of $13,102,000 or $.50 per common share in
the third quarter of 1993. The 1994 loss included a $30,000,000 writedown of
the book value of the Company's oil and gas properties due to a ceiling test
limitation and the 1993 loss included an extraordinary loss on extinguishment of
debt of $10,749,000.
REVENUE
The Company's oil and gas sales revenue increased by 3% to $26,623,000 in
the third quarter of 1994 from $25,754,000 in the third quarter of 1993. As a
result of property acquisitions, discoveries and extensions, natural gas
production levels for the 1994 period increased over the 1993 period, but these
increases were partially offset by the effects of property sales and normal
production declines. Oil production levels remained approximately the same in
the third quarter of 1994 as in the third quarter of 1993. The average sales
price for natural gas in the third quarter of 1994 was $1.82 per thousand cubic
feet of natural gas (MCF), a decrease of $.04 per MCF or 2% compared to the
average sales price of $1.86 per MCF in the third quarter of the prior year.
The average sales price for oil in the third quarter of 1994 of $15.97 per
barrel represented an increase of $.22 per barrel or 1% compared to the average
sales price of $15.75 per barrel in the same period of the prior year.
EXPENSES
Oil and gas production expense increased 11% to $5,419,000 in the third
quarter of 1994 from $4,897,000 in the comparable period of 1993. The increase
was due primarily to increased natural gas production. On an MCFE basis (MCFE
means thousands of cubic feet of natural gas equivalents, using a conversion
ratio of one barrel of oil to six MCF of natural gas), production expense
increased 5% in the third quarter of 1994 to $.40 per MCFE from $.38 per MCFE in
the third quarter of 1993.
General and administrative expense was $2,964,000 in the third quarter of
1994, an increase of 15% from $2,582,000 in the third quarter of 1993. Total
overhead costs (capitalized and expensed general and administrative costs) of
$4,911,000 in the third quarter of 1994 increased 13% from $4,332,000 in the
comparable period in 1993. Both increases are due primarily to employee
relocation expenses and increased insurance expense attributable to a larger
asset base.
Interest expense of $6,602,000 in the third quarter of 1994 increased 15%
from $5,753,000 in the comparable period in 1993 due to higher loan balances as
a result of recent capital spending.
Depreciation and depletion expense increased slightly to $15,869,000 in the
third quarter of 1994 from $15,734,000 in the third quarter of 1993 due to
increased production in the 1994 period. The depletion rate per unit of
production in the 1994 period was $1.16 per MCFE, compared to $1.20 per MCFE in
the prior year period.
Forest Oil and other companies utilizing full cost accounting are required
to perform quarterly ceiling tests and to write down capitalized exploration and
development costs to the extent such costs exceed the estimated value of oil and
gas reserves calculated in the manner prescribed by the rules of the Securities
and Exchange Commission (SEC). The SEC rules require the use of unescalated
current contract prices or spot prices for volumes not under contract in the
valuation of reserves. The Company's SEC PV10 reserve value (estimated future
net revenues discounted at 10%) was severely impacted in the third quarter
because its reserves are primarily natural gas which has experienced
-6-
<PAGE>
periods of price volatility since being deregulated, including a sharp decline
in the third quarter of 1994. The writedown results entirely from low natural
gas prices and is not the result of a decrease in the quantity of the Company's
oil and gas reserves. The writedown of the carrying value of oil and gas
properties will have no effect upon the Company's cash flow, liquidity or debt
covenants.
Presented below is a schedule of Changes in the Standardized Measure of
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves from
December 31, 1993 to September 30, 1994, prepared in accordance with Statement
of Financial Accounting Standards No. 69. Changes in the demand for oil and
natural gas, inflation and other factors make estimates inherently imprecise and
subject to substantial revision. This table should not be construed to be an
estimate of the current market value of the Company's proved reserves. The
information presented demonstrates that the writedown is entirely attributable
to a decrease in spot market prices for natural gas. Even though reserves have
been added through purchases, extensions, discoveries and revisions, the
increased value attributed to such reserves was more than offset by the impact
of decreasing prices.
<TABLE>
<CAPTION>
Nine Months Ended
September 30, 1994
-------------------
(In Thousands)
<S> <C>
December 31, 1993 $ 299,053
Changes resulting from:
Sales of oil and gas, net of production costs (51,039)
Net changes in prices and future production costs (82,301)
Net changes in future development costs 5,360
Extensions, discoveries and improved recovery 9,209
Previously estimated development costs incurred during the period 5,593
Revisions of previous quantity estimates 8,957
Sales of reserves in place (7,972)
Purchases of reserves in place 8,325
Accretion of discount on reserves at beginning of year before income taxes 24,251
Net change in income taxes 23,156
---------
September 30, 1994 $ 242,592
---------
---------
</TABLE>
The Company could have chosen to lessen or completely eliminate the need
for a writedown by entering into financial derivatives (swaps) and locking in
future natural gas prices. The Company would have had to contract approximately
one-third of its natural gas reserve base to avoid the entire writedown.
Company management decided not to enter into such contracts because it believes
the natural gas market is now at a cyclical low, and such arrangements would
ultimately be detrimental to the Company's shareholders. In addition, the
Company considered but chose not to adopt successful efforts accounting. It is
management's belief that full cost accounting remains the most appropriate
method of accounting for the Company's current mix of operations, despite the
quarterly ceiling test requirement.
Additional writedowns of the full cost pool may be required if prices
decrease, undeveloped property values decrease, estimated proved reserve volumes
are revised downward or costs incurred in exploration, development, or
acquisition activities exceed the discounted future net cash flows from the
additional reserves, if any.
-7-
<PAGE>
RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1994
NET LOSS
The net loss for the first nine months of 1994 was $35,892,000 or $1.34 per
common share compared to a net loss of $16,429,000 or $.91 per common share for
the comparable period in 1993. The 1994 net loss included a $30,000,000
writedown of the book value of the Company's oil and gas properties as described
above. The 1993 net loss included cumulative effects of changes in accounting
principles of $1,123,000 and an extraordinary loss on extinguishment of debt of
$10,749,000. The increase in operating revenues in the first nine months of
1994 from the properties acquired at the end of 1993 was more than offset by an
increase in production and depletion expense in the 1994 period. The weighted
average number of common shares outstanding during the nine months ended
September 30, 1994 was approximately 28,072,000 compared to approximately
20,032,000 in the corresponding period of the prior year due primarily to the
issuance of 11,080,000 shares of Common Stock in June, 1993.
REVENUE
The Company's oil and gas sales revenue increased by 13% to $87,588,000 for
the nine months ended September 30, 1994 from $77,598,000 in the comparable
period of 1993. Natural gas production levels for the 1994 period increased
over the 1993 period by 20% due primarily to property acquisitions. Oil
production levels for the 1994 period increased slightly from the 1993 period.
The average sales price for natural gas in the first nine months of 1994 was
$1.92 per MCF, an increase of $.02 per MCF or 1% over the average sales price of
$1.90 in the first nine months of the prior year. The average sales price for
oil in the first nine months of 1994 of $14.60 per barrel represented a decrease
of $2.56 per barrel or 15% compared to the average sales price of $17.16 in the
same period of the prior year.
The production volumes and weighted average sales prices during the periods
were as follows:
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
----------------------------- -----------------------------
September 30, September 30, September 30, September 30,
1994 1993 1994 1993
------------- ------------- ------------- -------------
(In Thousands)
<S> <C> <C> <C> <C>
Natural Gas
Production under long-term fixed price
contracts (MMCF) (1) 4,048 5,493 13,057 14,053
Average contract sales price (per MCF) (1) $ 1.78 1.73 1.78 1.63
Production sold on the spot market (MMCF)(2) 7,323 5,226 23,571 16,363
Spot sales price received (per MCF) $ 1.71 2.11 1.98 2.25
Effects of energy swaps (per MCF) (2) .14 (.12) .02 (.11)
--------- --------- --------- ---------
Average spot sales price (per MCF) $ 1.85 1.99 2.00 2.14
Total production (MMCF) 11,371 10,719 36,628 30,416
Average sales price (per MCF) $ 1.82 1.86 1.92 1.90
Oil and condensate (3)
Total production (MBBLS) 365 369 1,152 1,146
Average sales price (per BBL) $ 15.97 15.75 14.60 17.16
<FN>
(1) Production under long-term fixed price contracts includes scheduled
deliveries under volumetric production payments, net of royalties. See
"Volumetric Production Payments" below.
(2) Energy swaps were entered into to hedge the price of spot market volumes
against price fluctuation. Hedged volumes were 3,458 MMCF and 2,094 MMCF
for the three months ended September 30, 1994 and 1993, respectively, and
8,840 MMCF and 6,004 MMCF for the nine months ended September 30, 1994 and
1993, respectively.
(3) Oil and condensate production is sold primarily on the spot market. An
immaterial amount of production is covered by long-term fixed price
contracts, including scheduled deliveries under volumetric production
payments, net of royalties.
</TABLE>
-8-
<PAGE>
Miscellaneous net revenue increased to $2,299,000 in the first nine months
of 1994 from $1,717,000 in the comparable 1993 period. The 1994 amount includes
income from the sale of miscellaneous pipeline systems and equipment and the
reversal of an accounts receivable reserve. The 1993 amount included an
adjustment to reduce accrued severance taxes based on communications with the
applicable state taxing authority.
EXPENSES
Oil and gas production expense increased 21% to $16,647,000 in the first
nine months of 1994 from $13,789,000 in the comparable period of 1993. The
increase was due to increased natural gas production. On an MCFE basis,
production expense was $.38 per MCFE in the first nine months of 1994 and $.37
in the first nine months of 1993.
General and administrative expense was $7,553,000 in the first nine months
of 1994, a slight decrease from $7,556,000 in the first nine months of 1993.
Total overhead costs (capitalized and expensed general and administrative costs)
of $13,076,000 in the first nine months of 1994 increased 6% from $12,387,000 in
the comparable period in 1993, primarily due to employee relocation expenses and
increased insurance expense attributable to a larger asset base. The Company's
salaried workforce was 142 at September 30, 1994 and 133 at September 30, 1993.
The following table summarizes the total overhead costs incurred during the
periods:
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
------------------------------ -----------------------------
September 30, September 30, September 30, September 30,
1994 1993 1994 1993
------------- ------------- -------------- -------------
(In Thousands)
<S> <C> <C> <C> <C>
Overhead costs capitalized $ 1,947 1,750 5,523 4,831
General and administrative costs
expensed 2,964 2,582 7,553 7,556
--------- --------- --------- ---------
Total overhead costs $ 4,911 4,332 13,076 12,387
--------- --------- --------- ---------
--------- --------- --------- ---------
</TABLE>
Interest expense of $20,077,000 in the first nine months of 1994 increased
5% from $19,068,000 in the comparable period in 1993 due to higher loan balances
as a result of recent capital spending.
Depreciation and depletion expense increased 15% to $51,473,000 in the
first nine months of 1994 from $44,730,000 in the first nine months of 1993 due
to increased production in the 1994 period. The depletion rate per unit of
production averaged $1.17 per MCFE for the first nine months of 1994 and $1.18
per MCFE for the first nine months of 1993. At September 30, 1994 the Company
had undeveloped properties with a cost basis of approximately $41,824,000 which
were excluded from depletion, compared to $18,305,000 at September 30, 1993.
The increase is attributable primarily to the acquisition of undeveloped
properties in 1992 and 1993.
As described previously, the Company was required to record a $30,000,000
writedown of the carrying value of its oil and gas properties at September 30,
1994. Additional writedowns of the full cost pool may be required if prices
decrease, undeveloped property values decrease, estimated proved reserve volumes
are revised downward or costs incurred in exploration, development, or
acquisition activities exceed the discounted future net cash flows from the
additional reserves, if any.
As of December 31, 1993, there were no remaining deferred tax liabilities.
No tax benefits for operating loss carryforwards have been recorded in the first
nine months of 1994.
-9-
<PAGE>
CAPITAL RESOURCES AND LIQUIDITY
CASH FLOW
Historically, one of the Company's primary sources of capital has been
funds provided by operations, which has varied dramatically in prior periods
depending upon factors such as natural gas contract settlements and price
fluctuations, which are difficult to predict.
The following summary table reflects comparative cash flows for the Company
for the periods ended September 30, 1994 and 1993:
<TABLE>
<CAPTION>
Nine Months Ended September 30,
-------------------------------
1994 1993
------ ------
(In Thousands)
<S> <C> <C>
Funds provided by operations (A) (B) $ 48,811 41,174
Net cash provided by operating activities (B) 45,440 25,497
Net cash used by investing activities (15,398) (45,148)
Net cash provided (used) by financing activities (B) (35,128) 104,191
<FN>
(A) Funds provided by operations consists of net cash provided by operating
activities adjusted for the changes in working capital items.
(B) Includes $22,625,000 and $23,865,000 associated with the Company's
volumetric production payments for the nine months ended September 30, 1994
and 1993, respectively.
</TABLE>
SHORT-TERM LIQUIDITY AND WORKING CAPITAL DEFICIT
The Company has a secured master credit facility (the Credit Facility) with
The Chase Manhattan Bank, N.A. (Chase) as agent for a group of banks. Under the
Credit Facility, the Company is able to borrow up to $17,500,000 for acquisition
or development of proved oil and gas reserves, and up to $32,500,000 for working
capital and general corporate purposes, subject to semi-annual redetermination
at the banks' discretion. The total borrowing capacity of the Company under the
Credit Facility is $50,000,000. 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. 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
September 30, 1994, the outstanding balance under the Credit Facility was
$27,000,000 and the Company was in compliance with the covenants of the Credit
Facility.
On June 24, 1994 the Company's affiliate, CanEagle Resources Corporation
(CanEagle), sold a significant portion of its oil and gas properties in Canada
to a third party. In conjunction with this transaction, the Company received
payment of approximately $4,400,000 ($6,124,000 CDN) representing principal and
unpaid interest on the CanEagle subordinated debenture held by the Company. In
addition, the Company exchanged its remaining investment in CanEagle for
preferred shares of a newly formed entity, Archean Energy, Ltd.
The Company believes that it currently has adequate sources of short-term
liquidity to meet its working capital needs and to fund planned capital
expenditures. The Company continues to explore additional sources of short-term
liquidity, however, including sales of additional non-strategic properties and
excess equipment, and other measures.
-10-
<PAGE>
LONG-TERM LIQUIDITY
The Company has taken several significant steps to improve its long-term
liquidity. In 1993 the Company issued Common Stock and subordinated debt, the
proceeds of which were used in part, together with available cash, to redeem the
Company's long-term notes and debentures. In February 1994, the Company
redeemed the remaining $7,171,000 principal amount of its 5 1/2% Convertible
Subordinated Debentures.
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, as well as 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. The Company continues
to examine alternative sources of long-term liquidity, including public and
private issuances of equity and refinancing debt with equity.
VOLUMETRIC PRODUCTION PAYMENTS
As of September 30, 1994, deferred revenue relating to production payments
was $43,791,000. As of September 30, 1994, the annual amortization of deferred
revenue and the corresponding delivery and net sales volumes are set forth
below:
<TABLE>
<CAPTION>
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)
------------------- ------- ------- ------- -------
(In Thousands)
<S> <C> <C> <C> <C> <C>
Remainder of 1994 $ 7,885 51 4,365 43 3,522
1995 20,772 174 11,045 146 8,913
1996 7,579 87 3,721 73 3,003
1997 2,474 -- 1,410 -- 1,138
Thereafter 5,081 -- 2,886 -- 2,329
--------- ------ ------ ----- -------
$ 43,791 312 23,427 262 18,905
--------- ------ ------ ----- -------
--------- ------ ------ ----- -------
(1) Represents volumes required to be delivered to Enron net of estimated
royalty volumes.
</TABLE>
NONRECOURSE SECURED LOAN AND DOLLAR-DENOMINATED PRODUCTION PAYMENT
Under the terms of the Enron loan entered into in December 1993 and a
dollar-denominated production payment sold to a bank in February 1992, the
Company is required to make payments based on the net proceeds, as defined, from
certain subject properties.
The Enron loan, which bears annual interest at the rate of 12.5%, was
recorded at a discounted amount to reflect the conveyance to the lender of a 20%
interest in the net profits, as defined, of the Company's Loma Vieja properties
located in south Texas. At September 30, 1994 the principal amount of the loan
was $59,833,000 and the recorded liability was $56,381,000. 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
-11-
<PAGE>
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 currently estimates that the loan
balance will be increased by approximately $1,500,000 in the fourth quarter of
1994 and by approximately $1,600,000 in 1995 due to planned capital expenditures
and the effects of depressed natural gas prices. Estimated liability reductions
for 1996 through 1998, based on expected production and prices, budgeted capital
expenditure levels and expected discount amortization, are approximately
$2,600,000, $14,800,000 and $15,800,000, respectively. Payments, if any, under
the net profits conveyance will commence upon repayment of the principal amount
of the Enron loan and will cease when the lender has received an internal rate
of return, as defined, of 18% (15.25% through December 31, 1995).
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 September 30, 1994 the remaining
recorded liability was $18,911,000. 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 cannot
exceed 100% of the net proceeds from the subject properties. Forest retains a
management fee equal to 10% of sales from the properties, which is deducted in
the calculation of net proceeds. The Company's current estimate, based on
expected production and prices, budgeted capital expenditure levels and expected
discount amortization, is that remaining 1994 payments will reduce the recorded
liability by approximately $235,000. Estimated liability reductions for 1995
through 1998, under the same production, pricing, capital expenditure and
discount scenario are approximately $2,600,000, $780,000, $1,700,000 and
$3,500,000, respectively.
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 September 30, 1994, the Company had natural gas
swaps and collars for an aggregate of approximately 38 BBTU (billion British
Thermal Units) per day of natural gas during the remainder of 1994 at fixed
prices and floors (NYMEX basis) ranging from $1.90 to $2.33 per MMBTU (million
British Thermal Units) with a weighted average of $2.04 per MMBTU and an
aggregate of approximately 27.5 BBTU per day of natural gas during 1995 at fixed
prices and floors ranging from $1.90 to $2.40 per MMBTU with a weighted average
of $2.02 per MMBTU. Under the terms of the nonrecourse secured loan, the
Company also has the option to pay $0.10 per MMBTU in December 1994 to buy a
floor for 1995 at $1.70 per MMBTU on 11.8 BBTU per day. At September 30, 1994,
the Company had oil swaps for an aggregate of approximately 2,000 barrels per
day of oil during the remainder of 1994 at fixed prices ranging from $16.70 to
$18.75 (NYMEX basis) with a weighted average of $17.64 per barrel and an
aggregate of approximately 1,300 barrels per day of oil during 1995 at fixed
prices ranging from $16.70 to $17.75 per barrel with a weighted average of
$17.23 per barrel.
SUMMARY OF CASH FLOW CONSIDERATIONS AND EXPOSURE TO PRICE AND RESERVE RISK
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 50% of its oil production will not be subject to price
fluctuations in the fourth quarter of 1994. It is estimated that existing
volumetric production payments, energy swaps, collars and fixed contracts
currently cover approximately 48% (excluding the option to purchase the $1.70
floor described above) of the Company's anticipated natural gas production and
43% of its oil production for the year ending December 31, 1995. Currently, it
is the Company's intention to commit no more than 75% of its anticipated
production to such arrangements at any point in time. See "Hedging Program"
above.
-12-
<PAGE>
CAPITAL EXPENDITURES
The Company's expenditures for property acquisition, exploration and
development for the first nine months of 1994 and 1993, including overhead
related to these activities which was capitalized, were as follows:
<TABLE>
<CAPTION>
Nine months ended September 30,
1994 1993
------------- -------------
(In Thousands)
<S> <C> <C>
Property acquisition costs:
Proved properties $ 8,835 32,347
Undeveloped properties -- --
-------- --------
8,835 32,347
Exploration costs:
Direct costs 5,501 3,983
Overhead capitalized 414 442
-------- --------
5,915 4,425
Development costs:
Direct costs 6,693 4,609
Overhead capitalized 5,109 4,389
-------- --------
11,802 8,998
-------- --------
$ 26,552 45,770
-------- --------
-------- --------
</TABLE>
The Company's exploration and development expenditures for the last three
months of 1994 are expected to be significantly higher than in the first nine
months of the year as a result of higher levels of drilling activity. The
Company's expenditures for exploration and development for the remainder of 1994
are currently expected to be approximately $7,934,000 and $9,655,000,
respectively, including capitalized overhead of $109,000 and $1,705,000,
respectively. It is possible that some of these costs may be incurred in the
first quarter of 1995. Planned levels of capital expenditures are subject to
substantial revision.
During the remainder of 1994, the Company intends to continue a strategy of
acquiring reserves that meet its investment criteria; however, no assurance can
be given that the Company can locate or finance any property acquisitions. In
order to finance future acquisitions, the Company is exploring many options
including, but not limited to: a variety of debt instruments; the issuance of
net profits interests; sales of non-strategic properties, prospects and
technical information; joint venture financing; the issuance of common or
preferred equity of the Company; sale of production payments and other
nonrecourse financing; as well as additional bank financing. Availability of
these sources of capital will depend upon a number of factors, some of which are
beyond the control of the Company.
DIVIDENDS
The Company was required to pay dividends on its $.75 Convertible Preferred
Stock, when and if declared, in shares of Common Stock through 1993. On
February 1, 1994, a cash dividend of $.1875 per share on its $.75 Convertible
Preferred Stock was paid to holders of record on January 14, 1994. On May 1,
1994, a cash dividend of $.1875 per share on the $.75 Convertible Preferred
Stock was paid to holders of record on April 8, 1994. On August 1, 1994, a cash
dividend of $.1875 per share on the $.75 Convertible Preferred Stock was paid to
holders of record on July 8, 1994. On November 1, 1994, a cash dividend of
$.1875 per share on the $.75 Convertible Preferred Stock was paid to holders of
record on October 7, 1994. The Indenture executed in connection with the
11 1/4% Senior Subordinated Notes due 2003 and the Credit Facility contain
restrictive provisions governing dividend payments. Under the
-13-
<PAGE>
Credit Facility restrictions, the Company estimates that it may be prohibited
from paying preferred stock dividends in cash after the first quarter of 1995.
GAS BALANCING
It is customary in the industry for various working interest partners to
produce more or less than their entitlement share of natural gas from time to
time. The Company's net overproduced position decreased in the first nine months
of 1994 to approximately 8.5 BCF from approximately 10 BCF at December 31, 1993.
The Company currently estimates that approximately 1 BCF will be repaid in the
remainder of 1994 and 3 BCF will be repaid in 1995 under such agreements. In
the absence of a gas balancing agreement, the Company is unable to determine
when its partners may choose to make up their share of production. If and when
the Company's partners do make up their share of production, the Company's
deliverable natural gas volumes could decrease, adversely affecting gas revenue
and cash flow.
-14-
<PAGE>
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
*Exhibit 4.1 Amendment No. 2 dated as of August 31, 1994 to the Security
Agreement dated as of December 1, 1993 between Forest Oil Corporation and The
Chase Manhattan Bank (National Association), as agent.
Exhibit 10.1 Description of Employee Overriding Royalty Bonuses, incorporated
herein by reference to Exhibit 10.1 to Form 10-K for Forest Oil Corporation for
the year ended December 31, 1990 (File No. 0-4597).
Exhibit 10.2 Description of Executive Life Insurance Plan, incorporated herein
by reference to Exhibit 10.2 to Form 10-K for Forest Oil Corporation for the
year ended December 31, 1991 (File No. 0-4597).
Exhibit 10.3 Form of non-qualified Executive Deferred Compensation Plan (File
No. 0-4597), incorporated herein by reference to Exhibit 10.3 to Form 10-Q for
Forest Oil Corporation for the quarter ended June 30, 1994 (File No. 0-4597).
Exhibit 10.4 Form of non-qualified Supplemental Executive Retirement Plan,
incorporated herein by reference to Exhibit 10.4 to Form 10-K for Forest Oil
Corporation for the year ended December 31, 1990 (File No. 0-4597).
Exhibit 10.5 Form of Executive Retirement Agreement, incorporated herein by
reference to Exhibit 10.5 to Form 10-K for Forest Oil Corporation for the year
ended December 31, 1990 (File No. 0-4597).
Exhibit 10.6 Forest Oil Corporation 1992 Stock Option Plan and Option
Agreement, incorporated herein by reference to Exhibit 10.7 to Form 10-K for
Forest Oil Corporation for the year ended December 31, 1991 (File No. 0-4597).
Exhibit 10.7 Letter Agreement with Richard B. Dorn relating to a revision to
Exhibit 10.5 hereof, incorporated herein by reference to Exhibit 10.11 to Form
10-K for Forest Oil Corporation for the year ended December 31, 1991 (File No.
0-4597).
Exhibit 10.8 Forest Oil Corporation Annual Incentive Plan effective as of
January 1, 1992, incorporated herein by reference to Exhibit 10.8 to Form 10-K
for Forest Oil Corporation for the year ended December 31, 1992 (File No. 0-
4597).
Exhibit 10.9 Form of Executive Severance Agreement, incorporated herein by
reference to Exhibit 10.9 to Form 10-K for Forest Oil Corporation for the year
ended December 31, 1993 (File No. 0-4597).
Exhibit 10.10 Form of Settlement Agreement and General Release between John F.
Dorn and Forest Oil Corporation dated March 7, 1994, incorporated herein by
reference to Exhibit 10.10 to Form 10-K for Forest Oil Corporation for the year
ended December 31, 1993 (File No. 0-4597).
*Exhibit 11 Forest Oil Corporation and Subsidiaries - Calculation of Earnings
per Share of Common Stock.
*Exhibit 27 Financial Data Schedule.
*Exhibit 99 Second Amendment dated October 24, 1994 to the Retirement Savings
Plan of Forest Oil Corporation (File No. 0-4597).
* Filed with this report.
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed by Forest during the quarter for which
this report is filed.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
FOREST OIL CORPORATION
(Registrant)
Date: November 14, 1994 /s/ Daniel L. McNamara
------------------------------------------
Daniel L. McNamara
Corporate Counsel and Secretary
(Signed on behalf of the registrant)
/s/ David H. Keyte
------------------------------------------
David H. Keyte
Vice President and Chief
Accounting Officer
(Principal Accounting Officer)
<PAGE>
AMENDMENT NO. 2 TO SECURITY AGREEMENT
AMENDMENT NO. 2 TO SECURITY AGREEMENT dated as of August 31, 1994,
between FOREST OIL CORPORATION, a corporation duly and validly existing under
the laws of the State of New York (the "Company") and THE CHASE MANHATTAN BANK
(NATIONAL ASSOCIATION), a national banking association, as agent for the Banks
(as defined below) (in such capacity, together with its successors in such
capacity, the "Agent").
The Company, the lenders signatory thereto (the "Banks") and the Agent
are parties to a Credit Agreement dated as of December 1, 1993, as amended by
Amendment No. 1 dated as of December 28, 1993, Amendment No. 2 dated as of
January 27, 1994 and Amendment No. 3 dated as of June 3, 1994 (as amended, the
"Credit Agreement"), providing, subject to the terms and conditions thereof, for
loans to be made by said Banks to the Company in an aggregate principal amount
not exceeding $50,000,000. The Company and the Agent entered into a Security
Agreement dated as of December 1, 1993, as amended by Amendment No. 1 to
Security Agreement dated as of December 28, 1993 (as amended, the "Security
Agreement"), as a condition to the obligation of the Banks to make loans to the
Company pursuant to the Credit Agreement. The Company and the Agent, with the
consent of the Banks, wish to amend the Security Agreement to release from the
Lien of the Security Agreement certain properties, rights and interests and
accordingly, the parties hereto hereby agree as follows:
Section 1. Definitions. Except as otherwise defined in this Amendment
No. 2 to Security Agreement, terms defined in the Security Agreement and the
Credit Agreement are used herein as defined therein.
Section 2. Amendments. Subject to the satisfaction of the conditions
precedent specified in Section 4 below, but effective as of August 31, 1994, the
Security Agreement shall be amended as follows:
A. The following definition shall be added in alphabetical order in
Section 1 of the Security Agreement:
"Amendment No. 2 to Security Agreement" shall mean Amendment No. 2 to
this Agreement dated as of August 31, 1994.
B. Section 3 of the Security Agreement is hereby amended by adding
the following at the end of such Section:
"Notwithstanding any provision of Section 3 hereof to the contrary,
pursuant to Section 11.09 of the Credit Agreement, the Properties of the Company
described in Exhibit A to Amendment No. 2 to Security Agreement are excluded
from the definition of 'Collateral'."
Section 3. Representations and Warranties. The Company represents and
warrants to the Agent and the Banks that the representations and warranties set
forth in Section 8 of the Credit Agreement and Section 2 of the Security
Agreement are true and complete on the date
<PAGE>
hereof as if made on and as of the date hereof.
Section 4. Conditions Precedent. As provided in Section 2 above, the
amendments to the Security Agreement set forth in said Section 2 shall become
effective, as of August 31, 1994, upon the satisfaction of the following
conditions precedent.
A. Execution by All Parties. This Amendment No. 2 to Security
Agreement shall have been executed and delivered by each of the parties hereto.
B. Certificate. The Agent shall have received the certificate
provided for in Section 11.09 of the Credit Agreement in form and substance
satisfactory to the Agent.
Section 5. Release of Collateral. To the extent that the Security
Agreement covers any Property of the Company described in Exhibit A hereto, such
Property is hereby released and any security interests or Liens in favor of or
held by the Agent are terminated and at the Company's request, and at the
Company's expense, the Agent shall take such other actions as are necessary to
evidence the release and termination evidenced by this Amendment No. 2 to
Security Agreement.
Section 6. Miscellaneous. Except as herein provided, the Security
Agreement shall remain unchanged and in full force and effect. This Amendment
No. 2 to Security Agreement may be executed in any number of counterparts, all
of which taken together shall constitute one and the same amendatory instrument
and any of the parties hereto may execute this Amendment No. 2 to Security
Agreement by signing any such counterpart. This Amendment No. 2 to Security
Agreement shall be governed by, and construed in accordance with, the law of the
State of New York.
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this Amendment No.
2 to Security Agreement to be duly executed and delivered as of August 31, 1994.
FOREST OIL CORPORATION
By___________________________
Name: Kenton M. Scroggs
Title: Vice President
THE CHASE MANHATTAN BANK
(NATIONAL ASSOCIATION), as Agent
By___________________________
Name:
Title:
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this Amendment No.
2 to Security Agreement to be duly executed and delivered as of August 31, 1994.
FOREST OIL CORPORATION
By___________________________
Name: Kenton M. Scroggs
Title: Vice President
THE CHASE MANHATTAN BANK
(NATIONAL ASSOCIATION), as Agent
By___________________________
Name: Richard F. Betz
Title: Vice President
<PAGE>
EXHIBIT A TO UCC-3
FILING NO. 932089275
E X H I B I T "A"
Attached to and made a part of that certain Sales Agreement dated the 28th day
of June, 1994, by and between Forest Oil Corporation, as Seller, and Sandel
Energy, Inc., as Buyer.
Murry No. 1 and No. 2 Unit
Property No. 293015-010 and 293015-020
Waller County, Texas
OPERATOR: FOREST OIL CORPORATION
FOC WI: 30.00%
FOC NRI: 26.25%
Forest's interest in the above designated property is derived from Forest's
ownership of the leasehold estate created by the following lease:
<TABLE>
<CAPTION>
RECORDATION
LEASE NO. LESSOR LESSEE COUNTY DATE VOLUME PAGE
________________________________________________________________________________________________________________________
<S> <S> <S> <C> <C> <C>
Mary P. Bingham, et al Stanolind Oil and Gas Company, et al Waller 12/23/42 88 386
</TABLE>
INSOFAR AND ONLY INSOFAR as the above described leasehold is located in Section
94, Block 1, H&TCRR Co. Survey, Waller County, Texas, LESS AND EXCEPT 40.74
acres contained within the Katy Gas Consolidated Unit the current boundaries of
which are shown on Exhibit "B" of that certain Unit Agreement dated 5/2/66 a
counterpart of which is recorded in Volume 203, Page 638, Ded Records of Waller
County, Texas, INSOFAR AND ONLY INSOFAR as it pertains to the depths of 10, 000'
below the suface down to and including the stratigraphic equivalent of 11,400'
in the ARCO Murry No. 1 Unit, Well #1, located in said Section 94.
Subject to the Following Related Agreements:
1. Farmout Agreement (AR-72669) dated June 17, 1983, by and between Amerada
Hess Corporation, as Farmor, and ARCO Oil and Gas Company, as Farmee, as
amended by,but not necessarily limited to, Letter Agreements dated Septem-
ber 8, 1983, October 13, 1983, December 19, 1983 and December 21, 1983.
2. Operating Agreement (AR-72771) dated December 15, 1983 by and between
Atlantic Richfield Company,as Operator and Amoco Production Company,et al,
as Non-Operator.
3. Conveyance of Overriding Royalty between Forest Oil Corporation, "Grantor"
and Cactus Hydrocarbon III Limited Partnership, "Grantee", dated December
10, 1993, recorded in Volume 486, Page 295, Files No. 186399 of the Waller
County Records.
4. The obligations set out in the above described lease.
<PAGE>
EXHIBIT A TO UCC-3
FILING NO. 932089275
EXHIBIT "A"
Attached to and made a part of that certain Farmout Agreement between Forest Oil
Corporation and Enterprise Exploration & Production, Inc., dated April 20, 1994.
MONTY PROSPECT/P#-187011
PECOS AND TERRELL COUNTIES, TEXAS
<TABLE>
<CAPTION>
FOC RECORDING
LEASE NO. LESSOR LESSEE DATE DESCRIPTION DATA
________________ ____________________________ _____________ _______ ___________ ______________________________
<S> <S> <S> <C> <S> <S>
TX-187011-000001 Abilene Christian University Delmon Hodges 6/28/89 All of Section 34, BlK102, Book 648,Page 32-Pecos County
(4351-1) JHGibson Survey,Pecos Co.,TX
TX-187011-000002 Abilene Christian University Delmon Hodges 12/01/89 All of Section 32, Blk 102, Book 652,Page371-Pecos County
(4351-2) JHGibson Survey,Pecos Co.,TX
TX-187011-000003 Abilene Christian University Delmon Hodges 12/01/89 S/2 of Section 35, Blk 102, Book 80,Page479-Terrell County
(4351-3) JHGibson Survey,Terrell Co.,TX
TX-187011-000004 Abilene Christian University Delmon Hodges 12/01/89 S/2 of Section 33, Blk 102, Book 652,Page 376-Pecos County
(4351-4) JHGibson Survey,Pecos., TX
TX-187011-000011A Bowden Enterprises Delmon Hodges 12/14/89 N/2 of Section35,Blk102,
(4351-11A) J.H.Gibson Survey Book 652,Page 405-Pecos County
Pecos & Terrell Counties,TX Book 85,Page15-Terrell County
TX-187011-000011B Patricia A. Barry Delmon Hodges 12/11/89 Same as above Book 652,Page 407-Pecos County
(4351-11B) Book 85,Page 12-Terrell County
TX-187011-000011C Garon D. Cagle, Sr., et ux Delmon Hodges 12/14/89 Same as above Book 652,Page 410-Pecos County
(4351-11C) Book 85,Page 19-Terrell County
TX-187011-000011D John F. Schneider, et ux Delmon Hodges 12/14/89 Same as above Book 652,Page 412-Pecos County
(4351-11D) Book 85,Page 17-Terrell County
TX-187011-000011E Jane Anne Stinnett Delmon Hodges 12/14/89 Same as above Book 652,Page 414-Pecos County
(4351-11E) Book 85,Page 21-Terrell County
TX-187011-000011F R. S. Tapp & Company Delmon Hodges 12/14/89 Same as above Book 652,Page 416-Pecos County
(4351-11F) Book 85,Page 23-Terrell County
TX-187011-000011G Celeste Lucille Elsner,widow Delmon Hodges 12/11/89 Same as above Book 652,Page 418-Pecos County
(4351-11G) Book 85,Page 25-Terrell County
</TABLE>
Page 1 of 2
<PAGE>
MONTY PROSPECT/P#-187011
PECOS AND TERRELL COUNTIES, TEXAS
<TABLE>
<CAPTION>
FOC RECORDING
LEASE NO. LESSOR LESSEE DATE DESCRIPTION DATA
________________ ____________________________ _____________ _______ ___________ ______________________________
<S> <C> <C> <C> <C> <S>
TX-187011-000011H Exch. Natl. Bank of Jefferson Delmon Hodges 12/11/89 N/2 of Section35,Blk102,
(4351-11H) City, Missouri & Wm. H. Bates, JHGibson Survey, Book 652,Page 421-Pecos County
Co-Trustees of the Thomas Price Pecos & Terrell Counties,TX Book 85,Page 28-Terrell County
Gibson Trust Number 1
TX-187011-000011I Exch. Natl. Bank of Jefferson Delmon Hodges 12/11/89 Same as above Book 652,Page 424-Pecos County
(4351-11I) City, Missouri & Wm. H. Bates, Book 85,Page 31-Terrell County
Co-Trustees of Gaverne Gibson
Meade Trust Number 1
TX-187011-000011J Lucille R. Turner, a widow Delmon Hodges 12/11/89 Same as above Book 652,Page 427-Pecos County
(4351-11J) Book 85,Page 34-Terrell County
TX-187011-000012 Abilene Christian University Forest Oil 12/01/94 All of Section 32,Blk102,
(Top Lease of TX-187011-000002)** Corporation JHGibson Survey, currently being recorded in
Pecos County, Texas Pecos County
TX-187011-000013 Abilene Christian University Forest Oil 12/01/94 S/2 of Section 35,Blk102,
(Top Lease of TX-187011-000003)** Corporation JHGibson Survey, currently being recorded in
Pecos County, Texas Pecos County
TX-187011-000014 Abilene Christian University Forest Oil 12/01/94 S/2 of Section 33,Blk102,
(Top Lease of TX-187011-000004)** Corporation JHGibson Survey, currently being recorded in
Pecos County, Texas Pecos County
</TABLE>
** These leases only take effect should TX-187011-02, 03, & 04 expire by their
own terms on 12/1/94.
Page 2 of 2
<PAGE>
EXHIBIT A TO UCC-3
FILING NO. 932089275
North Oakvale Prospect 179027
Jefferson Davis County, Mississippi Page 1 of 3
EXHIBIT "A"
SCHEDULE OF LEASES
<TABLE>
<CAPTION>
FOC RECORDING DATA
LEASE # LESSOR LESSEE DATE DESCRIPTION BOOK PAGE
_______ ______ ______ ____ ___________ ____ ____
<C> <S> <C> <C> <C> <C> <C>
7046-4A Christine Dyess W. Tingle Savell 01/03/80 Sec. 17,20,21, T6N-R18W 133 249
7046-4B Gay Lloyd Dyess W. Tingle Savell 01/03/80 Sec. 17,20,21, T6N-R18W 133 252
7046-4C Charlene Dyess McPail W. Tingle Savell 01/03/80 Sec. 17,20,21, T6N-R18W 133 255
7046-4D Virginia Dyess W. Tingle Savell 01/03/80 Sec. 17,20,21, T6N-R18W 133 258
7046-4E Thomas Victor Dyess W. Tingle Savell 01/03/80 Sec. 17,20,21, T6N-R18W 133 261
7046-4F Peggy Dyess Wilson W. Tingle Savell 01/03/80 Sec. 17,20,21, T6N-R18W 133 264
7046-4G Pauline D. Jenkins W. Tingle Savell 01/03/80 Sec. 17,20,21, T6N-R18W 133 267
7046-4H Arthur Lee Dyess W. Tingle Savell 01/10/80 Sec. 17,20,21, T6N-R18W 133 269
7046-4I Delphie Mae D. Martin W. Tingle Savell 01/10/80 Sec. 17,20,21, T6N-R18W 133 271
7046-4J Robert Dyess W. Tingle Savell 01/10/80 Sec. 17,20,21, T6N-R18W 133 436
139 257
7046-4K Irene D. Jones W. Tingle Savell 01/10/80 Sec. 17,20,21, T6N-R18W 133 273
7046-4L Mrs. Mae Beil Dyess W. Tingle Savell 01/10/80 Sec. 17,20,21, T6N-R18W 133 275
7046-4M Bennie Ran Dyess W. Tingle Savell 01/30/80 Sec. 17,20,21, T6N-R18W 133 448
7046-4N Mildred D. Ford W. Tingle Savell 01/21/80 Sec. 17,20,21, T6N-R18W 133 460
</TABLE>
<PAGE>
Page 2 of 3
<TABLE>
<CAPTION>
FOC RECORDING DATA
LEASE # LESSOR LESSEE DATE DESCRIPTION BOOK PAGE
_______ ______ ______ ____ ___________ ____ ____
<S> <C> <C> <C> <C> <C> <C>
7046-4O Merlyn D. Chance W. Tingle Savell 01/30/80 Sec. 17,20,21, T6N-R18W 133 450
7046-4Q Bobbie D. Speights W. Tingle Savell 02/11/80 Sec. 17,20,21, T6N-R18W 133 521
7046-4R Nevis L. Dyess W. Tingle Savell 02/11/80 Sec. 17,20,21, T6N-R18W 133 523
7046-4S Mary Nell D. Bass W. Tingle Savell 02/11/80 Sec. 17,20,21, T6N-R18W 133 525
7046-4T Christine Dyess,Guard. W. Tingle Savell 03/24/80 Sec. 17,20,21, T6N-R18W 134 238
7046-5 Pauline Jenkins W. Tingle Savell 01/10/80 Sec. 17, T6N-R18W 133 277
7046-10B The Rankin Company Jacksoco Oil Company 03/12/74 Sec. 22, SE/4SW/4, T6N-R18W 86 243
7046-25A Delton Dyess, et ux Amoco Production Company 03/23/78 Sec. 17, T6N-R18W 119 122
7046-25B Toxie Dyess, et ux Pruet & Hughes Company 06/29/76 Sec. 17, T6N-R18W 97 209
7046-27A Maurice Smith1 Amoco Production Company 03/22/78 Sec. 17, T6N-R18W 119 100
7046-27B Ruby Etheredge Gillham Pruet & Hughes Company 08/02/76 Sec. 17, T6N-R18W 98 446
7046-27C Leonora Martinez Pruet & Hughes Company 08/18/76 Sec. 17, T6N-R18W 103 700
Kennington Myers
7046-27D Fred J. Lotterhos Pruet & Hughes Company 08/04/76 Sec. 17, T6N-R18W 99 413
7046-27E Grace B. Moss Marital Pruet & Hughes Company 08/18/76 Sec. 17, T6N-R18W 99 419
Trust
7046-27F Clyde E Moss Residuary Pruet & Hughes Company 08/18/76 Sec. 17, T6N-R18W 99 415
Trust
</TABLE>
<PAGE>
Page 3 of 3
<TABLE>
<CAPTION>
FOC RECORDING DATA
LEASE # LESSOR LESSEE DATE DESCRIPTION BOOK PAGE
_______ ______ ______ ____ ___________ ____ ____
<C> <S> <C> <C> <C> <C> <C>
7046-27G Suco Company Pruet & Hughes Company 08/18/76 Sec. 17, T6N-R18W 99 417
7046-27H Mabel McGehee Lillie Forest Oil Corporation 03/01/82 Sec. 17, T6N-R18W 155 515
7046-27I F. C. Atkinson, Indv., Forest Oil Corporation 01/02/82 Sec. 17, T6N-R18W 157 325
as Executor and Trustee
7046-27J Mrs. Fannie Kate M. Forest Oil Corporation 03/01/82 Sec. 17, T6N-R18W 155 517
Catchings
7046-27K Mrs. Fannie Kate M. Lee W. Cline 03/29/82 Sec. 17, T6N-R18W 155 603
Catchings, Guardian
7046-27L Lucille S. Chichester Forest Oil Corporation 07/08/82 Sec. 17, T6N-R18W 159 272
7046-28 Percy Dyess, et ux Amoco Production Company 03/15/78 Sec. 17, T6N-R18W 119 110
7046-29A Lonnie S. Dyess, Sr. Amoco Production Company 03/15/78 Sec. 17, T6N-R18W 119 112
7046-29B Roy G. Dyess Amoco Production Company 03/15/78 Sec. 17, T6N-R18W 119 114
7046-29C Edwin G. Dyess, et ux Amoco Production Company 03/15/78 Sec. 17, T6N-R18W 119 116
7046-30 Sammie L. Dyess, et ux Amoco Production Company 03/23/78 Sec. 17, T6N-R18W 119 120
7046-33 United State Lumber Co. Shubuta Oil Corporation 01/07/72 Sec. 17, N/2Ne/4, E/2SE/4NE/4, 83 495
N/2NW/4, NE/4SW/4 and
SW/4SW/4, T6N-R18W
Sec. 18, Entire section
except NE/4SE/4 and
SE/4SW/4, T6N-R18W
</TABLE>
<PAGE>
EXHIBIT "A" TO UCC-3
FILING NO. 932089275
<TABLE>
<CAPTION>
FOC
Lease No. Lessor Lessee Date Description Recording Data
________ ______ ______ ____ ___________ ______________
<S> <C> <C> <C> <C>
9064-5 U.S.A. Forest Oil Corporation 6/1/62 Block 309 Eugene Island Area, South Serial No. OCS-G-0997
Addition, OCS Lease Map, La. No. 4-A,
INSOFAR AND ONLY INSOFAR as said lease
lies within the confines of the following
described aliquots: W/2; limited to the
interval from the surface of the earth to
the stratigraphic equivalent of 7014'
(identified as the total depth of the Columbia
Gas Development Corporation OCS-G-1981 J-1 S/T #1
being 7,014' TVD and 8,385' MD) LESS AND EXCEPT
the "C-I" formation as seen in the interval
from 4,170' to 4,330' MD in the OCS-G-0997
No. 4 Unit Well.
192236-000001 U.S.A. Tenneco Oil Co. 10/1/79 That portion of Block 18 seaward Serial No. OCS-G-4082
et. al. of the Three Marine League line
measured from the historic
shoreline described in the United
States vs. Louisiana, No. 9 original
(394 U.S. 836), Sabine Pass Area, as
shown on OCS Official Leasing Map,
Texas Map No. 8, INSOFAR AND ONLY
INSOFAR as said lease lies within the
confines of the following described
aliquots: All
192242-000001 U.S.A. Texaco, Inc., et al 7/1/90 Block 280, Main Pass Area, South and Serial No. OCS-G-12102
East Addition, OCS Leasing Map,
Louisiana No. 10A, INSOFAR AND ONLY
INSOFAR as said lease lies within the
confines of the following described
aliquots: All
</TABLE>
<PAGE>
EXHIBIT A TO UCC-3
FILING NO. 932089275
EXHIBIT "A"
Attached to and made a part of Farmout Agreement dated June 14, 1993 between
Forest Oil Corporation and Anglo-Suisse Inc.
_________________________________________________________________
Oil & Gas Lease Subject To Farmout Agreement
____________________________________________
1) FOC Lease No. 1594-1
Lessor: A. A. McAllen, et al
Lessee: Hale Schaleben
Gross Acres: 26,597.00 acres, more or less
Lease Date: June 15, 1954
Recording Data: Volume 159, Page 347-350 of the Oil & Gas
Records of Hidalgo County, Texas
Interest Subject to Farmout Agreement
_____________________________________
Approximately 320 acres, more or less, in the Santa Anita Grant, Hidalgo County,
Texas, out of that certain 3000.00 acres described in that Partial Assignment
of Oil, Gas and Mineral Lease, dated July 25, 1956, between Delhi-Taylor Oil
Corporation, as Assignor, and Forest Oil Corporation, as Assignee, recorded in
Volume 189, Page 507-511 of the Oil and Gas Records of Hidalgo County, Texas,
beginning at the Northeast Corner of the 3000 acres, thence Southeast 2500 feet
along east line of said lease, thence Westerly 5576 feet parallel to the North
line of lease, thence Northerly 2500 feet parallel to East line of lease, thence
Easterly along North line of lease, 5576 feet to point of beginning.
<PAGE>
EXHIBIT A TO UCC-3
FILING NO. 932089275
EXHIBIT "A"
Attached to and made a part of Farmout Agreement dated June 28, 1993 between
Forest Oil Corporation and Anglo-Suisse Inc.
_______________________________________________________________________________
Oil & Gas Lease Subject To Farmout Agreement
____________________________________________
1) FOC Lease No. 1594-1
Lessor: A. A. McAllen, et al
Lessee: Hale Schaleben
Gross Acres: 26,597.00 acres, more or less
Lease Date: June 15, 1954
Recording Data: Volume 159, Page 347-350 of the Oil & Gas
Records of Hidalgo County, Texas
Interest Subject to Farmout Agreement
_____________________________________
Approximately 1076.29 acres, more or less, in the Santa Anita Grant, Hidalgo
County, Texas, out of that certain 3000.00 acre tract described in that Partial
Assignment of Oil, Gas and Mineral Lease, dated July 25, 1956, between
Delhi-Taylor Oil Corporation, as Assignor, and Forest Oil Corporation, as
Assignee, recorded in Volume 189, Page 507-511 of the Oil and Gas Records of
Hidalgo County, Texas, said 1076.29 acres described as beginning at the
Southeast corner of said 3000 acre tract; thence in a Northerly direction
parallel to East line of said tract, a distance of 5800 feet; thence in a
Westerly direction parallel to the South line of said tract, a distance of
8083.3 feet to a point on the West line of said 3000 acre tract; thence in a
Southerly direction parallel to the West line of said tract a distance of 5800
feet to the Southwest corner of said 3000 acre tract; thence in a Easterly
direction along the South line of said 3000 acre tract a distance of 8083.3 feet
to the point of beginning.
<PAGE>
Exhibit 11
FOREST OIL CORPORATION
Calculation of Loss Per Share of Common Stock
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
------------------------------- -------------------------------
September 30, September 30, September 30, September 30,
1994 1993 1994 1993
------------- ------------- ------------- --------------
(In Thousands Except Per Share Amounts)
<S> <C> <C> <C> <C>
PRIMARY LOSS PER SHARE:
Net loss $ (33,739) (13,102) (35,892) (16,429)
Less dividends payable on
Convertible Preferred Stock (541) (551) (1,621) (1,708)
---------- ---------- ---------- ----------
Net loss attributable to common stock
for primary loss per share calculation $ (34,280) (13,653) (37,513) (18,137)
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
Weighted average number of common
shares outstanding 28,135 27,525 28,072 20,032
---------- ---------- ---------- ----------
Primary loss per share $ (1.22) (.50) (1.34) (.91)
---------- ---------- ---------- ----------
FULLY DILUTED LOSS PER SHARE:
Net loss attributable to common stock, as above $ (33,739) (13,102) (35,892) (16,429)
Add:
Interest expensed on 5-1/2% Convertible
Subordinated Debentures -- 103 -- 309
Expenses related to the 5-1/2% Convertible
Subordinated Debentures -- 2 -- 5
Less:
Additional Federal income taxes -- 36 -- 107
---------- ---------- ---------- ----------
Loss applicable to fully diluted calculation $ (33,739) (13,033) (35,892) (16,222)
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
Common shares applicable to fully diluted calculation:
Weighted average number of common shares
outstanding, as above 28,135 27,525 28,072 20,032
Add:
Weighted average number of shares issuable
upon assumed conversion of 5-1/2% Convertible
Subordinated Debentures -- 714 -- 584
Weighted average number of shares issuable
upon assumed conversion of Convertible
Preferred Stock 10,083 10,273 10,083 10,618
---------- ---------- ---------- ----------
Common shares applicable to fully diluted calculation 38,218 38,512 38,155 31,234
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
Fully diluted loss per share* $ (.88) (.34) (.94) (.52)
---------- ---------- ---------- ----------
</TABLE>
*The fully diluted loss per share is not presented in the Company's financial
statements because the effects of assumed exercises and conversions were anti-
dilutive.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
condensed consolidated statements of income and condensed consolidated balance
sheets on pages 2 and 3 of the Company's Form 10-Q for the quarterly period
ending September 30, 1994, and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-1-1994
<PERIOD-END> SEP-30-1994
<CASH> 2,027
<SECURITIES> 0
<RECEIVABLES> 22,918
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 27,601
<PP&E> 1,172,431
<DEPRECIATION> 870,100
<TOTAL-ASSETS> 352,574
<CURRENT-LIABILITIES> 32,362
<BONDS> 200,911
<COMMON> 2,829
0
15,854
<OTHER-SE> 32,556
<TOTAL-LIABILITY-AND-EQUITY> 352,574
<SALES> 87,588
<TOTAL-REVENUES> 89,887
<CGS> 16,647
<TOTAL-COSTS> 24,200
<OTHER-EXPENSES> 81,473
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 20,077
<INCOME-PRETAX> (35,863)
<INCOME-TAX> 29
<INCOME-CONTINUING> (35,892)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (35,892)
<EPS-PRIMARY> (1.34)
<EPS-DILUTED> (1.34)
</TABLE>
<PAGE>
SECOND AMENDMENT TO
RETIREMENT SAVINGS PLAN
OF
FOREST OIL CORPORATION
WHEREAS, FOREST OIL CORPORATION(the "Company") has heretofore adopted the
RETIREMENT SAVINGS PLAN OF FOREST OIL CORPORATION(the "Plan") for the benefit of
its eligible employees; and
WHEREAS, the Company desires to amend the Plan;
NOW, THEREFORE, the Plan shall be amended as follows:
I. Effective as of January 1,1992, clause(2)of the last sentence of Section
3.6(b) of the Plan shall be deleted and the following shall be substituted
therefor:
"(2) amounts held in the suspense account shall be invested
and reinvested by the Trustee as directed by the Committee and
the suspense account shall share in the earnings or losses of
such investment; and"
II. Effective as of April 1, 1992, the following shall be added to the end
of Section 4.3 of the Plan:
"Further, notwithstanding any provision herein to the contrary,
the Committee may establish from time to time minimum percentage
increments pursuant to which elections and directions by Participants
with respect to the investment of their accounts shall be made."
III. Effective as of January 1, 1993:
1. The following new Sections 1.11A, 1.12A, 1.13A and 1.13B shall
be added to Article I of the Plan:
"1.11A `Direct Rollover' means a payment by the Plan to an
Eligible Retirement Plan specified by a Distributee.
1.12A `Distributee' means each (a) Participant entitled to
an Eligible Rollover Distribution,(b) Participant's surviving spouse
with respect to the interest of such surviving spouse in an Eligible
Rollover Distribution, and (c) former spouse of a Participant who is
an alternate payee under a qualified domestic relations order, as
defined in Section 414(p) of the Code,with regard to the interest of
such former spouse in an Eligible Rollover Distribution.
1.13A `Eligible Retirement Plan' means (a) with respect to a
Distributee other than a surviving spouse, an individual retirement
account described in Section 408(a) of the Code, an individual
retirement annuity described in Section 408(b) of the Code, an
annuity plan described in Section 403(a) of the Code, or a qualified
plan described in Section 401(a) of the Code,which under its provis-
ions accepts such Distributee's Eligible Rollover Distribution and
(b) with respect to a Distributee who is a surviving spouse, an
individual retirement account described in Section 408(a)of the Code
or an individual retirement annuity described in Section 408(b) of
the Code.
<PAGE>
1.13B `Eligible Rollover Distribution' means any distribution
of all or any portion of the accounts of a Distributee other than (a)
a distribution that is one of a series of substantially equal periodic
payment (not less frequently than annually)made for the life (or life
expectancy)of the Distributee or the joint lives(or joint life expect-
ancies)of the Distributee and the Distributee's designated beneficiary
or for a specified period of ten years or more, (b) a distribution to
the extent such distribution is required under Section 401(a)(9)of the
Code,(c)the portion of a distribution that is not includable in gross
income (determined without regard to the exclusion for net unrealized
appreciation with respect to employer securities), (d) a loan treated
as a distribution under Section 72(p) of the Code and not excepted by
Section 72(p)(2), (e)a loan in default that is a deemed distribution,
(f) any corrective distribution provided in Sections 3.4 and 3.6, and
(g) any other distribution so designated by the Internal Revenue
Service in revenue rulings, notices, and other guidance of general
applicability."
2. Section 3.7 of the Plan shall be deleted and the following shall be
substituted therefor:
"3.7.Rollover Contributions.
Qualified rollover contributions("Rollover Contributions")
may be made to the Plan by any Participant of amounts that are
"eligible rollover distributions" within the meaning of section
402(f)(2)(A) of the Code from an employees' trust described in
section 401(a) of the Code,which is exempt from tax under section
501(a) of the Code. A Rollover Contribution may be made to the
Plan irrespective of whether such eligible rollover distribution
was paid to the Participant or paid to the Plan as a "direct"
Rollover Contribution, but only if any such Rollover Contribution
is made pursuant to and in accordance with applicable provisions
of the Code and Treasury regulations promulgated thereunder. A
direct Rollover Contribution to the Plan may be effectuated only
by wire transfer directed to the Trustee or by issuance of a check
made payable to the Trustee,which is negotiable only by the Trustee
and which identifies the Participant for whose benefit the Rollover
Contribution is being made. Any Participant desiring to effect a
Rollover Contribution to the Plan must execute and file with the
Committee the form prescribed by the Committee for such purpose.
The Committee may require as a condition to accepting any Rollover
Contribution that such Participant furnish any evidence that the
Committee in its discretion deems satisfactory to establish that
the proposed Rollover Contribution is in fact such an eligible
rollover distribution and is made pursuant to and in accordance
with applicable provisions of the Code and Treasury regulations.
All Rollover Contributions to the Plan must be made in cash.
A separate account (a "Rollover Account" ) shall be maintained
under the Plan for each Participant who has made a Rollover Con-
tribution. A Rollover Contribution shall be credited to the
Rollover Account of the Participant for whose benefit such Rollover
Contribution is being made as of the Valuation Date coincident
with or next succeeding the date the contribution is paid to the
Trust. Amounts held in a Rollover Account shall be fully vested
at all times,shall be subject to withdrawal in the same manner as
amounts held in a Supplemental Contributions Account,and shall be
treated as though they were a part of the Participant's Supplemental
Contributions Account for all other purposes of the Plan."
<PAGE>
3. Section 7.6 of the Plan shall be deleted and the following shall
be substituted therefor:
"7.6 Direct Rollover Election.
This Section applies to distributions made on or after
January 1, 1993. Notwithstanding any provision of the Plan to the
contrary that would otherwise limit a Distributee's election under
this Section,a Distributee may elect,at the time and in the manner
prescribed by the Committee, to have all or any portion of an Eli-
gible Rollover Distribution(other than any portion attributable to
the offset of an outstanding loan balance pursuant to the Plan's
loan procedure) paid directly to an Eligible Retirement Plan
specified by the Distributee in a Direct Rollover. The preceding
sentence notwithstanding,a Distributee may elect a Direct Rollover
pursuant to this Section only if such Distributee's Eligible Rollover
Distributions during the Plan Year are reasonably expected to total
$200 or more. Furthermore, if less than 100% of the Distributee's
Eligible Rollover Distribution is to be a Direct Rollover, the
amount of the Direct Rollover must be $500 or more. Prior to any
Direct Rollover pursuant to this Section, the Distributee shall
furnish the Committee with a statement from the plan, account, or
annuity to which the benefit is to be transferred verifying that
such plan, account, or annuity is or is intended to be,an Eligible
Retirement Plan."
4. The following new Section 8.6 shall be added to the end of
Article VIII of the Plan:
"8.6. Direct Rollover of Withdrawals.
Any withdrawal under this Article VIII shall be subject to
the Direct Rollover election described in Section 7.6."
5. The following shall be added to the end of Section 14.13(b) of
the Plan:
"No less than 30 days and no more than 90 days before a Participant's
benefit pursuant to Sections 6.1,6.2,6.3, or 7.4 is to begin to be
paid,the Committee shall inform the Participant(or his Beneficiary,
if applicable) of his right to defer his benefit commencement date
and shall describe the Participant's(or Beneficiary's,if applicable)
Direct Rollover election rights pursuant to Section 7.6."
IV. Effective as of January 1, 1994, the third and fourth sentences of
Section 1.10 of the Plan shall be deleted and the following shall be substituted
therefor:
"Notwithstanding the preceding provisions of this Section 1.10, (a)
for purposes of determining each Employee's Actual Contribution Per-
centage and Actual Deferral Percentage hereunder, `Compensation'
shall mean the Employee's compensation(within the meaning of Section
3.6(c)(3)), determined prior to reduction thereof for elective
deferrals made by the Company on behalf of the Employee to a plan or
arrangement described in Section 125 or Section 401(k) of the Code,
and(b)for purposes of allocating the Company Profit-Sharing Contri-
bution for any Plan Year pursuant to Section 5.2, `Compensation'
shall mean the total of all wages, salaries, fees for professional
<PAGE>
service and other amounts received in cash or in kind by a Participant
for services actually rendered or labor performed for the Company
while a Participant to the extent such amounts are includable in
gross income, subject to the following adjustments and limitations:
(i) the following shall be excluded:
1. reimbursements and other expense allowances;
2. cash and noncash fringe benefits;
3. moving expenses;
4. Company contributions to or payments from this or
any other deferred compensation program, whether
such program is qualified under Section 401(a) of
the Code or nonqualified;
5. welfare benefits;
6. amounts realized from the receipt or exercise of a
stock option that is not an incentive stock option
within the meaning of Section 422 of the Code;
7. amounts realized at the time property described in
Section 83 of the Code is freely transferable or no
longer subject to a substantial risk of forfeiture;
8. amounts realized as a result of an election described
in Section 83(b) of the Code;
9. any amount realized as a result of a disqualifying
disposition within the meaning of Section 421(a) of
the Code;
10. any other amounts that receive special tax benefits
under the Code but are not hereinafter included;and
(ii) the following shall be included:
1. elective contributions made on a Participant's behalf
by the Company that are not includable in income under
Section 125, Section 402(e)(3), Section 402(h) or
Section 403(b) of the Code;
2. compensation deferred under an eligible deferred
compensation plan within the meaning of Section 457(b)
of the Code; and
3. employee contributions described in Section 414(h)
of the Code that are picked up by the employing unit
and are treated as employer contributions.
The Compensation of any Participant taken into account for purposes of the
Plan shall be limited to $200,000 ($150,000 for Plan Years beginning after
December 31, 1993) for any Plan Year with such limitation to be:
(A) adjusted automatically to reflect any amendments to
Section 401(a)(17) of the Code and any cost-of-living
<PAGE>
increases authorizedby Section 401(a)(17) of the Code;
(B) prorated for a Plan Year of less than twelve months and
to the extent otherwise required by applicable law; and
(C) in the case of a Participant who is either a five-
percent owner of the Company (within the meaning of
Section 416(i)(1)(A)(iii) of the Code) or is one of the
ten most Highly Compensated Employees for the Plan Year
and who has a spouse and/or lineal descendants who are
under the age of nineteen as of the end of a Plan Year
who receive Compensation during such Plan Year prorated
and allocated among such Participant, his spouse,and/or
lineal descendants under the age of nineteen based on
the Compensation for such Plan Year of each such indi-
vidual."
V. Effective as of August 10, 1994:
1. Section 1.4 of the Plan shall be deleted and the following shall
be substituted therefor:
"1.4 `Committee' means the Forest Oil Corporation
Employee Benefits Committee."
2. The first two sentences of Section 10.4 of the Plan shall be
deleted.
3. In each place where the word "shall" appears in the first
sentence of Section 10.6 of the Plan and in Section 10.7 of the Plan,such word
shall be deleted and the word "may" shall be substituted therefor.
VI. As amended hereby the Plan is specifically ratified and reaffirmed.
IN WITNESS WHEREOF, the undersigned has caused these presents to be
executed on this ______ day of ______________, 1994.
FOREST OIL CORPORATION
By:______________________
