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                                       Filed by Forest Oil Corporation
                                       pursuant to Rule 425 under the Securities
                                       Act of 1933 and deemed filed pursuant to
                                       Rule 14a-12 of the Securities Exchange
                                       Act of 1934


                                       Forest Oil Commission File No: 001-13515
                                       Forcenergy Commission File No. 000-26444
                                       Subject Company: Forcenergy Inc.


THE FOLLOWING IS A TRANSCRIPT OF AN INVESTOR AND ANALYST CONFERENCE CALL
REGARDING FOREST OIL CORPORATION'S SECOND QUARTER EARNINGS RELEASE.

INVESTORS AND SECURITY HOLDERS ARE ADVISED TO READ THE JOINT PROXY STATEMENT/
PROSPECTUS THAT WILL BE INCLUDED IN THE REGISTRATION STATEMENT ON FORM S-4 TO BE
FILED WITH THE SEC IN CONNECTION WITH THE PROPOSED MERGER BETWEEN FOREST AND
FORCENERGY. FOREST AND FORCENERGY WILL FILE THE JOINT PROXY STATEMENT/PROSPECTUS
WITH THE SEC. INVESTORS AND SECURITY HOLDERS MAY OBTAIN A FREE COPY OF THE JOINT
PROXY STATEMENT/PROSPECTUS (WHEN AVAILABLE) AND OTHER DOCUMENTS FILED BY FOREST
AND FORCENERGY WITH THE SEC AT THE SEC'S WEB SITE AT WWW.SEC.GOV. THE JOINT
PROXY STATEMENT/PROSPECTUS AND SUCH OTHER DOCUMENTS (RELATING TO FOREST) MAY
ALSO BE OBTAINED FOR FREE FROM FOREST BY DIRECTING SUCH REQUEST TO: FOREST OIL
CORPORATION, 1600 BROADWAY, SUITE 2200, DENVER, COLORADO 80202, ATTENTION:
DONALD H. STEVENS, VICE PRESIDENT AND TREASURER, TELEPHONE: 303-812-1400;
E-MAIL: INVESTORRELATIONS@FORESTOIL.COM.

FOREST, ITS DIRECTORS, EXECUTIVE OFFICERS AND CERTAIN MEMBERS OF MANAGEMENT AND
EMPLOYEES MAY BE CONSIDERED "PARTICIPANTS IN THE SOLICITATION" OF PROXIES FROM
FOREST'S SHAREHOLDERS IN CONNECTION WITH THE MERGER. INFORMATION REGARDING SUCH
PERSONS AND A DESCRIPTION OF THEIR INTERESTS IN THE MERGER WILL BE CONTAINED IN
THE REGISTRATION STATEMENT ON FORM S-4 WHEN IT IS FILED.

     FEMALE SPEAKER: At this time I would like to welcome everyone to the Forest
Oil Corporation 2000 earnings conference call. All lines have been placed on
mute to prevent any background noise. After the speaker's remarks,

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there will be a question and answer period. If you would like to ask a question
during this time, press the number one on your telephone key pad. If you would
like to withdraw your question press the pound key. Thank you. Mr. Don Stevens,
Vice President of Capital Markets and Treasurer, you may begin your conference.

     DON STEVENS: Good morning from Denver Colorado. With me today is Bob
Boswell, Chairman and CEO of Forest Oil. He'll give you an update following
which Dave Keyte, who's our Executive Vice President and CFO, will review the
numbers with you briefly.

     Before that I need to read a forward looking statement. This conference
call will include forward looking statements within the meaning of Section 27A
of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. Although the company believes that its expectations are based on
reasonable assumptions, it can give no assurance that expected results will be
achieved. Important factors that could cause actual results to differ materially
from those in the forward looking statements herein include the timing and
extent of changes in commodity prices for oil and gas, operating risks and other
risk factors as described in the Company's 1999 annual report on Form 10K as
filed with the SEC.

     In addition, investors and security holders are advised to read the joint
proxy statement/prospectus that will be included in the registration statement
on Form S-4

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to be filed with the SEC in connection with the proposed merger between Forest
and Forcenergy. Forest and Forcenergy will file the joint proxy
statement/prospectus with the SEC. Investors and security holders may obtain a
free copy of the joint proxy/statement prospectus either from the SEC or by
contacting Forest Oil. Forest, its directors, executive officers and certain
members of management and employees may be considered participants in the
solicitation of proxies from Forest's shareholders in connection with the
merger. Information regarding such persons and a description of their interests
in the merger will be obtained in the registration statement on Form S-4 when it
is filed.

     With that behind us, I'll turn the call over to David Keyte.

     DAVID: Thanks, Don. During the second quarter of 2000, Forest earned 11.4
million or 21 cents a share prior to translation loss. This is another record
quarterly earnings for the company adding to its first quarter record. Cash flow
before working capital changes totaled 36 million or 67 cents a share which also
represents a record for a quarter for the company. At this point, during the
first six months, the company has now out earned its previous annual record
established over 20 years ago and the record is one in an 84 year company so
it's quite an impressive record so far this year.

     The quarterly record streak continued with EBITDA over

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45 million dollars for the quarter. The major cause of the record performance
was the robust price environment and continued sequential production growth.
During the quarter, we produced about 226 million a day, up three percent from
the first quarter. Production, however, was negatively effected by property
sales and a government ordered shut in at Surmont. We continue to feel at this
point very comfortable with our previous guidance of 235 to 260 million cubic
feet a day on average for 2000. However, we are not going to model Forest
separately after this quarter. We will be doing our modeling on a pro forma
basis from this point forward.

     During the first quarter cash flow was essentially flat with capital
expenditures resulting in a stable net debt of about 385 million dollars. During
the quarter we made a strategic investment in Petroleum Place. They are a
private company which operates the vertical portal to the oil and gas industry.
We intend to utilize this investment to stay abreast of E-commerce initiatives
in the oil and gas business which will be particularly important in the merged
entity where capital expenditures are anticipated to be 350 to 400 million
dollars next year. We're hoping to gain significant amounts of synergy through
E-commerce initiatives. Petroleum Place recently announced a subsequent
investment by, and strategic alliance with, Halliburton.

     The differential widened on us in Canada much more

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than expected in the second quarter. The main reasons for this are that the
basis differentials in Alberta at AECO NIT has increased to now about 60 cents,
and by bringing on the Ft. Liard gas which has a lower realization to it affects
the overall portfolio of gas by about five cents and our fixed price contracts
within our net back pool affected us by about 10 cents. So that was a negative
surprise to us which we did not anticipate three months ago, but certainly the
differentials in Canada have widened out in this quarter. We don't view this as
a long term issue. We believe that the differentials will continue to tighten as
market forces work themselves out over the next three to six months.

     Due to the favorable pricing environment, we're moving our internal oil and
gas NYMEX pricing assumptions to 27.50 and four dollars respectively for the
last two quarters of this year. During the last conference call we estimated the
2000 EBITDA at 160 million to 190 million with cash flow of 125 to 155 million.
Based upon our new price assumptions, we now estimate EBITDA of 195 million to
225 million and cash flow of 160 million to 190 million. It should be noted the
price assumptions we are now using are about 6 to 12 percent respectively below
the current market for oil and gas.

     In our press release we provided certain pro forma information which gives
effect to the proposed merger with Forcenergy. There are a couple of things I
want to focus

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on here. First I think in our SEC filings we had indicated that we would be
somewhere between 480 and 490 million a day for the combined enterprise for the
quarter and we came in above that. The assets of Forcenergy are out performing
what we had anticipated and we are right in line with what we had anticipated.
Notably also cash flow for the new Forest Oil for the quarter was about 88 cents
a share or some $3.40 annually -- I'm sorry -- on an annualized basis. EBITDA
was about 97 million dollars -- or I'm sorry -- about 95 million bucks which
give you annualized rate of about 400 million dollars a year for EBITDA for the
new enterprise. And shares outstanding which has now been scrubbed down pretty
hard are right at 95 million. So we feel good about where we sit in terms of
accretion which should result in an increased valuation for the combined
enterprise as well as a stronger balance sheet which will give rise, we believe,
to a little more latitude in allocating our capital.

     Right now, we're just slightly better than fifty percent leverage rate.
We're slightly under that number. We anticipate with earnings from both
companies on a go forward basis that that number will continue to fall. We don't
anticipate any increase in debt as a result of the merger and at this point, it
seems to be looking as planned or slightly better than planned. We had a
combined management meeting to discuss capital allocation as well as plans for
2001 about three weeks ago and we'll be

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communicating our 2001 budget at the time of the closing of the merger.

     In modeling third quarter pro forma production, we're suggesting that
people use a model range of 470 to 480 million a day. There are a couple of
factors for this; one is that on the Forest Oil side we have a significant
amount of drilling that's going on in the Gulf of Mexico and the timing on
bringing that production on is uncertain although some of those discoveries have
been announced and Bob will get into that a little later. And secondly, the
production at Forcenergy we're still not certain about. We believe it's very
strong, but their projects for the remainder of the year are mainly OBO
projects; therefore a timing of those projects are out of the hands of the guys
at Forcenergy. So we're suggesting that people use a model range of 470 to 480
million a day. We believe it'd be very safe on that range. The valuation of the
company looks very strong at that range.

     With that, I'll turn it over to Bob and he'll take you through an
operational update.

     BOB: Thank you, Dave. The second quarter was highlighted by activities
related to the proposed merger with Forcenergy. As previously announced we
reached an agreement with Forcenergy to merge on July 10 by exchanging 1.6
shares of Forest Oil common stock for each share of Forcenergy common stock as
well as purchasing the Forcenergy preferred stock for Forest common stock. I'm

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happy to report that our merger plans are on track. We have filed the requisite
filings with the SEC, which are currently being reviewed. We've begun
development of an integration plan and identified the team which will be
assembled to develop the details of the plan and have responsibility for its
implementation. The plan is designated to capture at least 10 million in annual
savings to create new efficiencies and values on the economies of scope and
scale and to minimize negative effects on personnel and operational momentum.

     We recently held a meeting of senior operational personnel from both
companies to initiate efforts related to development of our 2001 business plan.
Included in this plan are activities associated with the sale and
rationalization for approximately 100 BCFE of non-core assets over the course of
the next two years. I was pleased by the rapport of the meeting, the extensive
portfolio of projects and opportunities for growth for the combined company. I'm
highly confident that this transaction will create exceptional value for both
sets of shareholders and a company that will be well positioned to realize on
one of the highest quality exploration portfolios assembled for a company of
comparable size.

     We expect the transaction to close towards the end of October or first part
of November and to hit the ground running with our integration plan. The result
will be the tenth largest North American independent, the fifth largest

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independent producer on the shelf on the Gulf of Mexico, and a company with an
unparalleled portfolio of growth opportunities for its size.

     At this point in time, I'd like to give you a brief review of Forest
operations during the first half of the year. The company has been busy
executing on its 2000 business plan. In the first half of the year, the company
spent approximately 40 percent of its capital budget and expects to fully
complete its plan for the year despite weather and equipment delays which have
hampered the first part of the year and are part -- and are expected to prevail
for the last part.

     Approximately one half of capital expense to date has been on drilling. The
company through the first half of the year has drilled 22 wells, 16 of them
being successful. You're beginning to see the results of this drilling effort
with production increasing quarter to quarter. Production for the first half of
the year was approximately on budget and growth has been expected throughout the
remainder of the year from the remaining drilling programs and from wells which
are currently being put on line or are in the processing of being completed.

     In Canada, the company drilled 11 wells during the first half of the year
with ten of them being successful. Five of the wells were in the our foothills
plays at Narraway and Cutpick where we have working interests varying from 40 to
50 percent and operate. A pipeline has

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been built into the Narraway area. One well has been put on production at the
rate of 3.5 million cubic feet per day. One well is waiting hook up. A third
well is being drilled. At Cutpick we have ordered pipe and will commence shortly
on construction for the pipeline that will be operative in November. The company
has four wells ready to hook up and expects to drill and complete at least two
more wells for hook up before the end of the year. The company will be
conducting an ongoing development program in these areas in cretaceous stacked
age sands which produce sweet gas. The company has in excess of 70,000 gross
acres in these areas which will provide it with an ongoing development program
over the next two years.

         Our  Narraway  acreage has also been offset by what appears to be three
successful  deeper wells most likely in the Belloy formation which produces high
deliverability sour gas. As result of this activity the company expects to drill
a deep test on its acreage next year. The company also expects to drill two more
wells on New Foothills prospects before the end of the year. One is an 8000 foot
test of our federal  prospects  with Petro Canada which is north of our Narraway
acreage  The second is a lateral  re-entry  with Shell in the  Southern  Alberta
foothills  around their prolific  Waterton gas field.  We are in a joint venture
here with Shell  shooting 3-D seismic  looking for similar  thrust sheets to the
Waterton field

     In the Northwest Territory the company recently spud

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its third exploratory well on the Nahanni Devonian carbonate thrust play. This
well is between our initial discovery well P-66 and Chevron's discoveries on a
license that is contiguous to our license on the south. The P66 well in which we
have a 50 percent working interest was put on line this past May. This well has
been flowed at a steady state rate of 20 million cubic feet of gas per day and
50 barrels of water per million. And this was flowing to mid July when it was
shut-in for a Westcoast plant turn around. The well has recently been brought
back on production and we expect it to produce at the 20 million cubic feet per
day rate.

     Chevron's well was completed open hole with 7 inch tubing and was reported
at an initial producing rate of 70 million cubic feet per day. Our exploration
well which was recently spudded has the license designation of C31. We expect
that well will take from 90 to 120 days to drill and test but we expect to know
the results by around year end. Elsewhere in the territory we plan to hook up
one gas well in the Liard area on the Shallow Mattson gas play this winter and
to drill at least one additional exploration well there.

     In the Norman Well's area, 400 miles north of Liard we expect to conduct a
2-D seismic shoot on our acreage and to reenter the Nota Creek well we drilled
two years ago to evaluate its oil potential.

     In our western business unit we have drilled two

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discoveries and one dry hole. The two discoveries are in the Southern part of
the Jonah field in Wyoming and have demonstrated excellent production rates for
this tight gas sand field. The first well here is currently producing around 10
million cubic feet per day. The second well after completing six or seven fracs
is producing at approximately 12 million cubic feet a day. The company expects
to drill one additional well in this area before the end of the year where it
has an average working interest of approximately 60% and operates.

     The Western business unit also has been conducting a deep recompletion
program in the Vermejo field in West Texas which has been successful. Here we
are re-completing wells in the Ellenberger formation at 18,000 feet with good
initial results.

     Moving South into the Gulf of Mexico onshore business unit, we've been
completing field studies for our south Louisiana field. The result of these
field studies have been encouraging. A number of new drilling prospects have
been identified. Drilling on these prospects will commence 2001. This business
unit is ahead of its production estimates and it has drilled two wells thus far
this year out of a program of six. One of the wells in the McAllen field was
completed successfully and the second well drilled in the Atchafalya Bay was
dry.

     Into the Gulf of Mexico offshore, the Gulf group started off a little bit
slow this year with the two first

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wells being dry, it has since made up on this by drilling three successful wells
in a row. This business unit is budgeted to drill 14 wells this year. Its
discoveries are Eugene Island 147 where we have a 25 percent working interest,
Eugene Island 292 with 45 percent working interest, and Eugene Island 53 where
we have a 100 percent working interest. The Eugene Island 53 well has not
reached TD but has sufficient reserves identified to be classified as discovery.
We had a rig problem on the well and had to temporarily abandon it until a rig
can be brought to location to finish drilling. The deeper target sands not yet
penetrated are the primary target in this well.

     In addition to the drilling program conducted thus far, the offshore
business unit made two acquisitions which increased our working interest in two
core properties. The company increased its interest in the High Island 116 area
where we spudded a third well this week following two prior discoveries on this
block. We now own a 100 percent working interest in this block. We also acquired
additional interest in roughly 16 blocks around the Eugene Island 292 complex
where we recently made a discovery. We've increased our working interest here
from approximately 22 percent to 45 percent. Eugene Island 292 complex is one of
the largest gas fields in the Gulf of Mexico. We made the initial discovery here
in the 1960's. Most of the production is from shallower sands less than

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6000 feet depth. We acquired a 3-D cable bottom shoot and we're looking both for
shallow exploitation opportunity and deeper exploration opportunity on the 292
complex.

     International. On the international front we've been equally busy. This
marks the first year within the business unit where they were able to turn
interpretive skills into drilling prospects. The company drilled its first
international wildcat in Thailand earlier this year. This high potential
prospect was drilled to a depth of roughly 6000 feet for a cost of approximately
1.5 million dollars and logged wet on the downthrown side of a major fault which
dissected the structure.

     In Switzerland, the company is preparing to spud on August 12, the first
exploration well drilled in this country in 11 years. This is a tight gas sand
play where we hope to utilize American technology to develop a potentially large
field that is crisscrossed by pipelines importing gas into the country. The well
which keys off data from wells that've been drilled by the government looking
for nuclear waste disposal sites has been evaluated by experts in tight gas
reservoirs from around the world and has determined that this reservoir should
be productive. We have a partner who will pay 60 percent of the drilling cost
and 100 percent of the testing and completion costs for a 40 percent interest.
We should have this 9000 foot well down and tested by the end of September.

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     In South Africa the company has contracted rigs from Pride-Foramer to drill
four wells with lineation fields. Drilling is scheduled to commence towards the
first of October. The company has completed a development study of the field and
is currently pursuing contracts for commercialization of the field. The company
has a signed a letter of intent with Mossgas, a South African parastatal which
operates a 30,000 barrels a day gas to liquids plant on the southern cape. We
examined the constructions of the pipeline. The delivery is approximately 200
million cubic feet of natural gas per day for 30 years. The company is also
examining other gas to power projects and gas to liquids possibilities along the
western coast of South Africa. Forest is pursuing a black empowerment partner or
partners for participation in development and commercialization in the field as
well as other potential industrial partners.

     The company also intends to spud an exploration well in Albania during the
fourth quarter on an oil prospect with estimated potential of 200 million
barrels. Occidental is the operator and Forest Oil has a 30 percent working
interest in this prospect. This is a mountain front thrust play where three
thrusts stack up on top of each other. The bottom and the top sheets have
discovered oil. The middle sheet which has not been tested is what we are
drilling. The well will probably take six or seven months to drill and should be
evaluated by the latter part

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of the first half of 2001.

     This concludes my remarks on operations. As you can tell, the company's
experiencing success on a number of fronts, expect to see production growth
throughout the remainder of the year well into 2001. At this point in time,
we'll open up the conference call for questions.

     MALE SPEAKER: Are there any questions?

     FEMALE SPEAKER: At this time I would like to remind all participants if you
would like to ask a question, please press the number one on your telephone key
pad. Your first question comes from Shannon Nome of Bank of American Securities.

     SHANNON: Hey. Good morning, guys.

     MALE SPEAKER: Hi, Shannon.

     MALE SPEAKER: Good morning, Shannon.

     SHANNON: Just curious in terms of mid year reserves and I know we don't
obviously do mid year reserves at mid year, but just noting -- you know, DD&A
rates continue to creep a bit. You know, do you have any targets for production
replacement this year or finding cost targets this year you can share with us at
this point?

     MALE SPEAKER: Shannon, we have our business plan and under our business
plan we expect to replace before any assets sales 120 to 150 percent of our
production. And our finding costs should be in around the $1.20 range if prices
don't fall and service costs don't run too much.

     SHANNON: Okay.

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     MALE SPEAKER: We've tried to anticipate that.

     MALE SPEAKER: But the $1.20, Shannon, is higher than our current DD&A rate
so you may see that creep continue.

     SHANNON: Okay.

     MALE SPEAKER: I think the other thing, Shannon, if you look at the first
part of the year about -- only about half of our money was spent on drilling
which added reserves, the other half was on infrastructure and land and that
adds to the -- part of that adds to the incremental DD&A.

     SHANNON: All right. Okay. Thank you.

     FEMALE SPEAKER: Your next question comes from Ken Beer with Johnson Weiss.

     KEN: Hi, guys. Actually just a follow up on that -- on the service cost
side, Bob, give us some thoughts as to you have -- how you get your arms around
that. I know back in `97, y'all were pretty quick to back away from spiraling up
Gulf of Mexico rig rates. You know, what's your position or stance now?
Obviously you've got a lot more areas of operations where you put dollars but
can you give us a sense of what you're seeing on the service cost side and what
you can do about it?

     MALE SPEAKER: Sure, Ken. The service cost has risen by about 20 percent
thus far on average. It varies -- you know, from area to area and from type of
services and these sorts of things. Those -- you know, the real concern for us
is not as much the increase in service cost as it is the

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decrease in quality of -- of service and the condition of equipment and those
sorts of things. So -- and that has historically been a bigger cause of cost
increase than the actual price. We -- we expect the market to be tight. We also
wanted the benefit of scope and scale from the combination is that we will be a
larger purchaser and through that I think we'll be able to negotiate longer term
relationships and as a consequence better prices and we'll be able to lock in
the quality we want.

     KEN: Fair enough. Just to shift gears one second. I'm heading up in Canada
for a moment. In terms of the timetable for, I guess, now the C31 well, if you
assume everything goes right which obviously it never does, but if it goes on
schedule, what's the timetable there to actually get production on line and, you
know, getting paid for gas flowing.

     MALE SPEAKER: I -- Ken, we expect to have that well down in 90 to 120 days
and after that we would probably conduct 30 days of testing and completion and
hook up. It may take slightly longer than that given weather conditions and
things of that nature, perhaps 60 days, but this well is right on the pipeline
route. So it's not going to -- it's not going to be a long time related to
hooking up and laying the line to get it to flow.

     KEN: Okay. So I mean, essentially it would be this upcoming winter you'd be
flowing if all works according to plan.

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     MALE SPEAKER: Yes. That's what we would expect.

     KEN: All right. Well, good enough. Let me step back for now. Thanks, guys.

     MALE SPEAKER: Okay. Thank you.

     FEMALE SPEAKER: Your next question comes from Jared Carson with Dain
Rauscher Wessels.

     JARED: Hi. Good morning. Enjoying a lot of success there in Cutpick with
the addition of the second rig. Do you have an idea of how many wells you might
target for `01?

     MALE SPEAKER: Yeah. Jared, we're trying to -- we're looking at that right
now as part of our 2001 business plan. The preliminary notion is to keep two
rigs drilling on the -- pretty much a continual basis through 2001 and that
would imply anywhere from six to eight wells next year.

     JARED: And so the -- the plant that you have that you mentioned will be
probably on line in December, will that be for production from both Cutpick and
Narroway, I presume here? Narroway being that sour.

     MALE SPEAKER: No. Actually at this stage, Narroway -- the gas there is
sweet gas and it goes into a separate pipeline situation.

     JARED: Okay.

     MALE SPEAKER: The Cutpick is a new pipeline and we will be producing sweet
gas through it. It's sized for 40 million a day without compression. I think the
four wells

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we've tested thus far, we're expecting to produce on a steady state basis of
roughly 22 million a day. So we've got some -- a little bit of running room
there and we've put compression on the line to increase its flow capacity.

     JARED: Great. And one final question. I missed the number on the Mossgas
gas LOI. What was the rate?

     MALE SPEAKER: It would be 200 million a day.

     JARED: Okay. Thank you.

     FEMALE SPEAKER: Thank you. Your next question comes from Tom Parker with
Chase Securities. Go ahead please.

     TOM: Can you give us an idea of how much production you lost due to the
problems at Surmont and how much from property sales?

     MALE SPEAKER: Yes, Tom. We lost about 2.3 million a day on property sales,
about a million and a half a day on the Surmont shut-in

     TOM: Okay. And then at Ft. Liard can you remind me on what your realization
is relative to the Canadian benchmark? What's the differential on that?

     MALE SPEAKER: Go ahead.

     MALE SPEAKER: Yeah. I think I can, Tom. Let me look and see. We were
getting in July at Liard before the plant turn around, we were getting $3.37 per
MCF Canadian. That's probably about -- that's probably about two and a quarter
U.S. Our royalties are about 20 cents, field operations about a dime, so I think
we're a net back $1.95 out of Liard in July at the wellhead.

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     TOM: Okay. And then in South Jonah as you move -- go into 2001, how much
more do you have to do there?

     MALE SPEAKER: We have one more well we're going to drill before the end of
the year. We're shooting 3-D seismic and from that we may define some additional
locations.

     TOM: And then in terms of -- what well will come on in the third quarter
from the gulf? Sounds like most of it's fourth quarter. Am I right in that?

     MALE SPEAKER: Well, let's see. I think on 292 we're going to be hooking
that up and we're doing a simultaneous completion and hook up with the drilling
so that should be on in September. At High Island 116 we should have down and
drilled middle -- it'll be on during the fourth quarter. At Eugene Island 53
we've ordered a caisson and flow line and we'll try and get that on as soon as
possible. It may be as early as October. So some of these will be coming on a
little bit earlier. I think the Eugene Island 147 is scheduled to come in on --
and be put on line in December right now. So we're trying to accelerate that.

     MALE SPEAKER: The biggest production hit in the Gulf is going to happen
when the secondary sands run out in the 116 wells. We can get up to the primary
zones and those are much higher rate zones than -- and ones that will -- will
drive production significantly out of the Gulf, but it's a -- waiting game
there. Good news is you've got more reserves. Bad news is you can't get to the
high rate yet.

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     TOM: Any kind of preliminary expectation on that or is it just too hard to
say right now?

     MALE SPEAKER: I think, Bob, you can correct me here. I think we've been
expecting it every week for the last eight weeks so.

     MALE SPEAKER: This is a kind of a unique situation where the wells out --
both wells are out performing the amplitude. So we're going to keep producing it
as long as they produce. They're both producing in the 15 million a day range
and those are nice wells. The zones that we're going up to -- the better zones
than the -- the B1 wells have never been tested but it's the lower zones, we got
initial rates of around 50 million a day. So we have some pretty high
expectations for those higher zones, but you don't know `til you pop them.

     TOM: Great. Thank you.

     FEMALE SPEAKER: Thank you. Your next question comes from John Lydecker with
Whitman. Go ahead please.

     MALE SPEAKER: Hello. We lost that one.

     FEMALE SPEAKER: I do apologize, sir. He withdrew his question. Your next
question comes from David Snow --

     DAVID: Yes. Hi. I'm wondering -- I saw just yesterday that Enron oil and
gas is moving into the McKenzie. I'm wondering if you have any idea how close
they are to your wells and whether this could be any synergy or would that be
competition or how you look at that?

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     MALE SPEAKER: Well, I -- I have not seen that announcement. I'm not
surprised. This is an area that has great potential. We would view them -- and
it's a very large area. We would view them as naturally as good healthy
competition. But in a very positive light. We think obviously very highly of
Enron Oil and Gas and this is a remote enough area and a large enough area that
we aren't too worried about bumping into each other.

     DAVID: Are you going to be able to take the gas -- oil out if you're
successful there?

     MALE SPEAKER: At Norman wells there's the in bridge pipeline that is built
into that area. It -- it moves -- has capacity to move about 50,000 barrels a
day and it's currently only moving about 20,000 barrels a day. So the answer is
yes.

     DAVID: How come you didn't finish testing it two years ago?

     MALE SPEAKER: Well, we got in there and the weather window is pretty short
there and we needed to get the completion and rig that we were going to do the
testing out of there it would be stacked literally for a year at a cost to us.
And then at the following winter oil prices were in the $12 range and we didn't
feel like we wanted to go spend money on an oil prospect at that point in time.

     DAVID: Is this a major reserve prospect or how could you characterize it?

     MALE SPEAKER: Well, I would characterize it as large

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by continental U.S. lower 48 onshore potential. It's a -- but we're in a new
frontier area. We don't have calibrated logs. Some of these things look good on
the log, but you never know `til you get in and try to work them. So obviously
- -- it has a lot of running room on it if we're successful on the testing.

     DAVID: What? In the range of 100 million or more than that in barrels?

     MALE SPEAKER: Yeah. That's a good approximation.

     DAVID: Okay. What's the sixth well that you're going to drill in the
Cutpick area? Where is that going to go?

     MALE SPEAKER: Well, we have -- we have an interest in 60 to 70,000 acres
there and we've been -- we shot 3D and we're just more or less going on a
development program across a -- kind of a thrust that runs along the front of
the mountain range. So its location will be -- I believe it's to the north of
our existing well.

     DAVID: Okay. And just back on the Norman wells, who is your partner --
you're 50 percent with who there?

     MALE SPEAKER: It was Ranger, but Ranger farmed out to Grey Wolf drilling
and Grey Wolf is a Canadian drilling company not to be confused with U.S.
drilling company and it has -- its ownership has a significant owner in Abraxas
which is a U.S. E&P company which has been active in Canada for several years.

     DAVID: Okay. When you said 100 or 500, is that a range of possibly what
you're looking at there?

                                                                         Page 25

     MALE SPEAKER: No. No. That's too large.

     DAVID: 100.

     MALE SPEAKER: Yeah. I -- that's a round number. I mean we've -- based on
our seismic we can map this particular reservoir but frankly at this stage, we
don't even need to know if it will produce.

     DAVID: Are your royalties pretty good up there.

     MALE SPEAKER: Yeah. Yeah. We have royalties that started about four percent
and then escalate from there and they -- the government has an option to convert
into a permanent royalty or a -- a net profits interest.

     DAVID: What is that going to convert into if it converts to a net profits?

     MALE SPEAKER: I think they -- it's a working interest and I think it's a 30
percent working interest or a ten percent royalty. It's something along those --
I haven't looked at those in several months, but it's a favorable royalty regime
and their decision will be based upon kind of their evaluation of which
economics is the best one.

     DAVID: Okay. Thank you.

     MALE SPEAKER: Thank you.

     FEMALE SPEAKER: Thank you. Your next question comes from Howard Slinker
with Slinker and Company.

     HOWARD: Hello, everybody.

     MALE SPEAKER: Morning.

     HOWARD: If I understand it right your contract with Mossgas alone would be
enough to use up all the gas in that

                                                                         Page 26

field that is now defined over 20 years of course. That's correct.

     MALE SPEAKER: No. Well, Howard, that's -- that's just based on these
delineation wells and proving up, you know, a couple of TCF's of gas. We expect
this field could be larger than that. These delineation wells will help give us
a sense of that. But no, it's not -- it wouldn't use up all the gas. This is
assuming the drilling of the wells over a seven year period.

     HOWARD: But you're going to tell them what? 200 B a year?

     MALE SPEAKER: 200 million cubic feet a day.

     MALE SPEAKER: That's 73 B.

     HOWARD: Excuse me 73 B a year.

     MALE SPEAKER: Yeah.

     HOWARD: I made a 70-- I meant 75. And over 20 years that's-- isn't that a T
and a half?

     MALE SPEAKER: Yeah.

     MALE SPEAKER: Yeah.

     HOWARD: Yeah. So that's what I meant. As it now stands you think that a T
and one half before you start looking for more. Is that correct?

     MALE SPEAKER: Yeah. That's our -- you know, that's a good number. We think
it could be quite larger than that.

     HOWARD: Yeah. Obviously.

     MALE SPEAKER: But we've got -- we've got a lot of work to do.

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     HOWARD: Okay. I just wanted to clarify that. Thanks.

     MALE SPEAKER: Sure.

     FEMALE SPEAKER: At this time, there are no further questions, sir. You may
do your closing remarks.

     MALE SPEAKER: Okay. Yes. No more questions so we want to thank everyone for
joining us on the conference call today. You should have our press releases. If
you don't you can go to our web site and obtain those at ForestOil.com. And we
would welcome any additional interest or questions you might have. Thank you.

     FEMALE SPEAKER: This concludes the Forest Oil Corporation 2000 earnings
corporation conference call. You may all disconnect.