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Forest Oil Corp. (NYSE:FST)

Q3 FY08 Earnings Call

November 4, 2008, 2:00 PM ET

Executives

Patrick J. Redman - Director of Investor Relation

David H. Keyte - EVP and CFO

H. Craig Clark - President and CEO

J.C. Ridens - EVP and COO

Analysts

Tom Gardner - Simmons & Company International

Gil Yang - Citigroup

Brian Singer - Goldman Sachs

Andrew Coleman - UBS

Dan McSpirit - BMO Capital Markets

David R. Tameron - Wachovia Securities

Operator

Good afternoon. My name is Dennis and I will be your conference operator today. At this time I would like to welcome everyone to the Forest Oil Corporation Third Quarter Earning Teleconference. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions].

I will now turn the call over to Mr. Patrick Redman, Director, Investor Relations, please go ahead sir.

Patrick J. Redman - Director of Investor Relation

Thank you and good afternoon everyone. I want to thank you for participating on our third quarter 2008 earnings conference call. We have joining us today Craig Clark, President and CEO; Dave Keyte, Executive Vice President and CFO; and J.C. Ridens, Executive Vice President and COO.

I'd like to caution you about our forward-looking statements. All statements other than statements of historical facts that address activities and outcomes that force expects, assumes, plans, believes, budgets, forecasts, projects, estimates or anticipates or other similar expression about what will, should, or may occur in the future are forward-looking statements. Please carefully review our cautionary language regarding forward-looking statements that is contained at the end of our press release.

I will now turn the call over to Dave Keyte. Thank you.

David H. Keyte - Executive Vice President and Chief Financial Officer

Thanks, Pat and good morning and thanks to all for listening from Denver where we have snow in the mountains, ski season has started, and Denver has snow on the forecast for tomorrow.

Second-quarter results were largely in line with our expectations with the exception of price differentials which blew out in the mid continent area particularly in September. Sales volumes increased to about 3% sequentially despite losing about $60 million in data, hurricanes and pipeline problems. This coupled with higher oil and gas prices and consistent cost control led to our very positive results. As has become the norm, increased cash margins led the way to achieving our stellar results.

The drivers here were a 55% increase in revenue per Mcfe to $8.28 and flat cash cost at $2.50 per Mcfe compared to the corresponding period of 2007. This combined to generate cash margins of $5.78 per unit in 2008, a 228% increase year-over-year from 285% in 2007. Differentials in the Mid-Con area increased substantially during the quarter, from the norms of about $0.85 to $0.90 to almost $2.50 in our marketed baskets during the quarter. This blowout caused by gas supply competition from the Gulf, reverted to our pipes as well as mild weather in the Midwest markets. Fortunately the gas markets in South Texas and in Canada where we sell almost 50% of our gas were unaffected by this and kept the company wide differentials from getting out of control.

The overall cash cost per unit this quarter was consistent with last year at about $2.50. It was lead by reductions in direct operating expense offset by increases in ad valorem and production taxes. We continue to generate exceptional cost results in the toughest of environments. This is a critical attribute for a company to have won the businesses and resource plays. This business can often have more economic challenges than technical challenges and cost control can mean a difference to it being able to make money or not in a low commodity price environment. This is one of Forest's most famous attributes and one it continues to serve us well presently. Our DD&A rate continued to our... continued to increase slightly to $2.86, as there were downward volume revisions due to low SEC price realizations in the Mid-Continent on September 30, 2008.

Our current tax increased due to a $3.1 million cash payment made to the Government of Gabon on sale of our assets there. After September 30, we liquidated about 40 million a day of our 2009 natural gas hedges to address counterparty credit issues. We expect to re-establish these hedges by year end with different counterparties. We are also considering additional NYMEX in basis hedges in light of the delays in our asset sales packages. Our original thought was to forego further hedging as assets sales would reduce our physical volumes sold. Since our view here is now changed, more hedges may be warranted. As to our plan forward in 2009, we dug out our 2004 to 2007 play book and will be reestablishing CapEx within this discretionary cash flow and moderating projected growth. We'll formalize our 2009 plan before our next earnings release.

I want to make a couple of comments here about liquidity and this is certainly first and foremost in many investors' minds and all spaces of investment. At September 30, 2008 Forest had $575 million of liquidity under its credit facility. Other than at June 30, 2008, this is the highest quarter end liquidity Forest has had ever in its 92 year history. During 2008, Forest took aggressive steps to increase its liquidity. In the second quarter, we increased our bank facility by $800 million to $1.8 billion at a pricing grid of 100 to 175 basis points. We also raised $250 million in high yield debt owed in 2019 at the rate of slightly over 7.2%. This additional liquidity of over $1 billion was to position ourselves as we have said before for what we believed was going to be a best in class acquisition market.

In addition, to raising this liquidity for acquisitions, we also announced at April 1st, at our analyst meeting property sales of $300 million to $500 million to prefund three years of CapEx in excess of cash flow. The steps we took in the second quarter positioned us to confidently proceed on a focused drilling program designed to deliver 15% organic growth and also to enable us to acquire core area assets to add to our most dominant positions. We have executed on both, the acquisition plan and the drilling plan. Of the $1 billion of acquisition money raised we spend about $900 million of cash and bought $1.2 billion of high quality assets that were exclusively in our core area of East Texas and Texas Panhandle. We also undertook capital program, which easily delivered the hope for growth and will likely exceed discretionary cash flow by less than the 10% advertised earlier also as planned.

As we announced divesture program, which was to fund three years of CapEx net excess of cash flow, we have executed a $100 million property sales and have another $250 million package pending. As noted in our press release, the counter party to the pending transaction contacted us yesterday to ask to revise the terms of the sales due to significant decreases in their liquidity. While no revised terms have yet been negotiated or agreed to, we still expect to close this transaction with this party or others, but possibly on altered terms. If we do not close this transaction, we will still have generated $100 million of cash via the closed sales, which will pay for our CapEx spending in excess of discretionary cash flow in 2008 as planned.

Without the Rockies sales, or in the case of Rockies sales and further property sales, we expect to end 2008 with liquidity of about $400 million to $600 million respectively. This is a high level of liquidity historically for this company. We also have tentatively prepared a 2009 capital plan to ensure adequate liquidity under our credit facility. This capital plan will not only be at or below discretionary cash flow, but will be designed to quarter production growth in 2009 over 2008.

In conclusion, because of the foresight that garnered significant liquidity in April and May, the asset base of Forest and its opportunity set is now far superior to the beginning of the year. Liquidity at September 30, 2008 was better, and at beginning of the year, and also better than at March 31, 2008. And for that matter, anytime before 2008. Further, we have now demonstrated the ability of the company to quickly ramp production by pressing lightly on the net CapEx accelerator. Therefore the company's operation is in a great shape and liquidity is ample and at historic highs.

Looking forward, we planned to enter 2009 with a capital plan reminiscent of 2007 to... or 2005 to 2007, where we will spend CapEx less then cash flow and moderate our growth. I couldn't help with also add a valuation sector here and I apologize for that, but I have to do it. Valuations in our sector like most others that are trading at levels really seen. And I remember the time when the market cap for Forest and others were actually trading below their book values. In fact, at its low Forest was trading at 65% of its book value. Just to put it in perspective, if we take the market value of our debt and the market value of our equity, the business has the following trading characteristics. It traded at $1.99 per pro forma Mcfe. This pro forma assumes absolutely no organic growth in our reserve base this year.

It also trade at $8800 per flowing Mcfe per day based on mid point fourth quarter guidance. These two particular metrics have not been seen in the asset markets since 2003 to 2004 when NYMEX gas prices were $5.50 and $6 and oil was about $30 to $40. We are also trading at four multiple on EBITDA on a trailing 12 months, 4.3 multiple of EBITDA based on annualized fourth quarter EBITDA at guidance mid point [Technical Difficulty]

Operator

Ladies and gentlemen, there seems to be some technical difficulty with the conference. Everyone please hold, your lines will be on silent until the conference resumes.

David H. Keyte - Executive Vice President and Chief Financial Officer

Okay, shall I go on.

Operator

Yes, go ahead.

David H. Keyte - Executive Vice President and Chief Financial Officer

Sorry about that. We had a phone outage here in Denver. We are now on cell phone, so I hope everybody can hear. Let me start where I was at the foreign evaluation. Towards a formal multiple on EBITDA based on trailing 12 months at 4.3 multiple of EBITDA based on annualized fourth quarter EBITDA guidance midpoint. We've also run this valuation based on $6 and $5 gas and the impact was to increase these multiples to $4.6 and $4.9 respectively. $4.9 times EBITDA at a $5 NYMEX price, remarkable.

Finally I took a look at the proved reserve base for the company and at September 30, 2008, based on realized prices of $5.85 held flat forever and current costs which arguably are somewhat high, the proved reserves are valued at approximately PV16 and there is no value for probables, possibles, land, drilling rigs or mid stream assets in this company at this time. These are certainly unprecedented times for valuation and clearly do not reflect Forest's inventory of over 14,000 drilling locations with 7.6 Tcfe of reserved potential not including the Shale' or the Shale's potential of 5000 locations and 9.6 Tcfe of reserved potential. As well as the value of this business which is built on a very low cost structure.

This is not whining, it is merely pointing out facts which should be considered when the fog lifts and investors realize that we produced required products and capital flows to equity once again. With that I will turn this little cell phone over to Craig for his comments.

H. Craig Clark - President and Chief Executive Officer

Okay, thanks Dave. Sorry about the phones, I guess I shouldn't have taken a little bit on our phone service. But life goes on in the oil field 365 days a year. As Dave detailed we had another excellent quarter in terms of adjusted earnings and cash flow.

In addition to our solid operating and spending execution, the results come from significantly increase cash margin. This highlights strategies we've talked about for some time. Control cost and focus to create substantial margins. In fact whether it's an up cycle or a down cycle, at least we do some thing to prepare for the future.

Some of the things we have done that when I noticed in the past maybe more popular Davis and folks. Things like capital discipline tied to cash flow levels, margin protection through cost control, G&A targets, NGL extraction, favorable tax structure and rear again top line ownership, avoiding low margin plays when we got out of the Rocky mountains' over a year ago. Constantly upgraded our assets by funding these acquisitions with divestitures. We improved our portfolio, I really believe that and that's a portfolio not one single play. So we can allocate or reallocate capital for best results. We now have option value in selecting the best economics, and I really like this optionality. We're not dependent over the extensive acreage expiring near term. In times of hot plays, we view sanity in those. We view science and including corporate deals to maintain a low cost of entry.

We have no more productions shifting contracts. Only tax and royalty terms in everywhere we operate in the world. Gabon was our last peer signatory. We traded value as we exit these countries like Gabon. But last but not least we start preparing our bank facilities as Dave mentioned and debt maturities a year ago. We are already and focused on A&B to trade value for years. As a reminder... the Gulf used in expiration well over a year ago, the gas ripped was $6.75. Again, in this quarter, we had solid operational execution, and again it's a mix of data points to validate our strategy in science and quality of the assets. We had some good data points in both, our major shale plays with an offset operator vertical test in Quebec and multiple successes on our Haynesville acreage including a stand alone well in our Haynesville.... J. C will mention came in over 4 million a day. We even drilled our Bristol [ph] Barnett Shale to-date and over 4 million a day in new accounting. J.C. Ridens will go over these highlights and many of these other areas following my comments.

In addition to the success in our shale plays, we had good data points in our so called frontier, which is really exploration and remained how highly South Louisiana and South Texas. More great points added on our tight-gas sand place, the ones we do the best. It was often noticed that we drilled the first vertical well ever in the Greater Buffalo Wallow area at over 10 million a day, and the West Texas Panhandle vertical, our newest acquisition already has 3 million a day in the shallower parts to the North.

Our best horizontals in East Texas are now Arkoma in Canada were also completed in the third quarter. We even added a nice 4 million a day horizontal on our newest East Texas Buffalo Wallow acquisition in the good old Gilmer field in East Texas. So far, so good. The successes in other J.C. will cover. We again added to our extensive portfolio locations we can select from. It's nice to be able to select and have that optionality in the current environment as opposed to chasing lease expirations.

The only thing that wasn't on the schedule in the quarter was the hurricane interruptions at two of them Gustav and Ike. Our asset basically saw no major damage and our outages were almost a solely result of third party plan and pipeline distributions. All-in-all, our people and our assets do pretty well during the storm.

Still our net production was up sequentially for the third quarter, 3% from last quarter, which would have been a whopping 6% sequentially without the storm and pipeline outages, you can see that we were ahead of schedule with new production records and some of the same growth in Buffalo Wallow in East Texas.

The Arkoma Basin has noted recently here, the new production record that J.C. will talk about at 45 million a day far away better than the 41 we entered 2008 with. As usual we are off to a good start on our newest acquisition in Greater Buffalo Wallow in East Texas. On the E&B CapEx side, we spent approximately 400 million in the quarter, bringing our 2008 total to $936 million. This is a 103% of our cash flow year-to-date. We've been there, done that. This is quite a bit higher in the second quarter but as you will catch you up its on pace with the guidance we issued.

The third quarter had higher activity due mainly four factors, increase towards oil activity in East Texas, Arkoma. Start up activity in our two major Shale plays, Haynesville and Urika [ph], lease hold acquisitions in East Texas, South Texas, and Canada and pipe purchases including moving inventory out of Houston prior to hurricane Ike, which is awarded rigs waiting on pipes in the U.S.

Overall we drilled 395 gross wells year-to-date and a 97% success rate. That's around 160 wells in the third quarter alone. Our success rate has remained at 97% throughout the year and even last year even with more exploration projects. We currently have approximately 60 operated wells and approximately 20 non-operated wells to complete currently which should give us a head start on a good fourth quarter and entering into '09. As our CapEx plan wants to spin near cash flow, our operated rig count peaked during the third quarter at around 47 rigs and is currently at 40 rigs.

We anticipate being at 30 to 35 rigs at the end of '08 which coincidently was our rig count in the first quarter of this year, so been there done that. We have been very diligent in our rig selection process in terms of which rig is peaking. We plan to employ the rigs that show themselves to be the most efficient and offered me efficiency before over the past few years. The rest will be sent home.

At our analyst conference earlier this year, we went at sensitivities on our major plays of $6 NYMEX and they exceeded our investment for rigs. So our greatest challenge is not economics. Basis differentials that Dave alluded to, now we have resembled the post hurricane Rita and caused widened basis in Mid-Continent into lesser extent premium but we have already narrowed on the strip so based on the strip they are coming back in line somewhat. However Canada and South Texas basis behaved.

Again it's nice to have a portfolio to cushion these types of events. I should also note that we are seeing lower drilling cost in the field in terms of rig daily rate prices and other services. We are now beating our 2009 services and think drilling cost will be lower in 2009. We are however seeing in the industry as we talked about several months ago, some delays for has high string frac coffins, specifically resin coated bauxite on deep oils industry wide.

On the LOE side, its business as usual with cost control. With cost basically flat again although as a deferred third quarter volume from hurricanes inflated the cost per unit by about a nickel per Mcfe. Cost was important to us last year and the year before as they are today. And we are as good at it as anybody in this area. The only reason costs are up slightly from a year ago and slightly as the word is production taxes. Let there be no confusion on this call. Before I turn the call over to J.C., I need to comment on the plans for the current environment.

First I would like to call it margin war. Currently our upstream producers need to extract as much margins as possible because pressure from both commodity prices and cost. Forest Oil has been focused on margin extraction and capital allocation throughout my tenure. We have had god results over the past five years to prove it and we have used cash flow to guide our END CapEx spinning over the same period.

We don't need to fund source from divestures to execute our capital programs because we don't consider the sale of producing properties in our free cash flow calculations. So wouldn't you expect us to perform well in this environment? We plan for this type of pricing scenario, been working on margin all along.

While I start evaluation metrics a day referred to as cheap as ever been despite good performance, we expect to re-establish our out performance as our successful business model has been around for a while, shines in a period of lower commodity prices if those persist. I will now turn J.C. over... the call over to J.C. for some great operations highlights.

J.C. Ridens - Executive Vice President and Chief Operating Officer

Thanks Craig. We have three business units that are battling it out for first place in the production areas. So I'm going to go through them in order of the current production rate. Western business units, in first place slightly at this point. Production in the Greater Buffalo Wallow Area reached a peak grade of 65 million cubic feet equivalent per day during the quarter which excludes the Cordillera acquisition. Our average IP for the 20 wells drilled in the quarter was 4.9 million cubic feet per day. Importantly, the first well drilled and completed on the newest acquisition properties had an IP of over 3 million cubic feet per day. This is on the shallow portion north of the main Buffalo Wallow field, and was a very solid result for our first well especially when you consider the wall costs here are cheaper than in the deeper part of the play, which is in the southern areas.

Post acquisition, we had 12 rigs started in the field. This makes us the number one driller in the Texas Panhandle on an acreage base that now totals 90,900 net acres. Another significant development in Buffalo Wallow will be studying our first grass roots for horizontal later this year. In the Delaware Basin, our first 2008 Haley well was completed for 7.2 million cubic feet equivalent per day. The second well has reached TD and has been cased. This well is pending completion, which we're looking forward to based on the shale seen during drilling. We will have production results from this well in the fourth quarter.

Our third well is ready to start some of the drilling contractor finishes the well the rig is currently on. We've got a 100% in these wells. Eastern business unit which trails western ever so slightly at this point in production. Production in East Texas, in North Louisiana reached 72.6 million cubic feet equivalent per day in the quarter excluding the new acquisition. This production rate was driven by good drilling results in both, the vertical as well as horizontal, Cotton Valley well. And we had good vertical Haynesville wells also. We drilled 18 wells in the quarter in this area. Of these 18 wells, 3 were horizontal Cotton Valley wells which had initial rates as high as 9.9 million cubic equivalent per day. The average IP for all three wells was 6 million cubic feet per day and these are the best results that we've had to-date.

We also got a good start on the Cordillera property set with the horizontal Cotton Valley well in Gilmore. That came in at 4 million cubic feet per day into a high pressure system. This is the best well in this field to-date as well. Since we've started the horizontal program, we drilled a total of 12 horizontal wells with the average IP being 5.4 million cubic feet per day.

Our horizontals program is expanded to the Haynesville as well. Our first operated Haynesville horizontal is now drilling. We are encouraged by the vertical wells that we have drilled with one of those wells having an initial rate of 4.4 million cubic feet per day. This well is holding up really well and it makes it one of the best vertical wells we have ever drilled in East Texas in any zone completed. To-date, we have drilled 10 Haynesville verticals wells with 100% success. In some of these well, co-mingling at Haynesville and Cotton Valley interval. Overall the IPs from these 10 wells have ranged from 1.5 million cubic feet to 4.4 million cubic feet per day. Our acreage position in East Texas and North Louisiana has expanded to 144,000 net acres. Of that we have got about 106,000 acres of Haynesville rights. On our entire acreage position, we had eight rigs running during the quarter.

In the Arkoma area, we reached a net peak production rate of 55.7 million cubic feet per day and we averaged 40.1 million during the quarter. Unfortunately we were severely impacted by pipeline downtime during the quarter to the tune of almost 5 million cubic feet per day. We're still experiencing problems with the third party pipeline as they take corrective actions for the pipe failure they experienced.

At the analyst conference we shut an expected 2008 rate of $43 cubic feet per day. We have beating that projection by several months absent outline downtime.

We drilled 29 operated wells during the quarter with a 100% success rate in the Arkoma. Initial rates ranged from 1.5 to 3.6 million cubic feet per day. The Arkoma horizontal program continues to yield good result with three new completions coming online in the quarter with maximum initial rate of 5 million cubic feet per day and the average of the three being 3.1 million cubic feet per day.

Our acreage position in the Arkoma is up to 41,000 net acres and we had four operated rigs running on that acreage in the quarter. Down in the Southern business unit we drilled 20 wells in the quarter with a 90% success rate. Initial rates from these wells were as high as 7 million cubic feet per day from our Wilcox program.

Our growth acreage position in the Wilcox and Vicksburg trend has increased to approximately 149,000 acres. One of our more significant Wilcox completion was on the legacy Forest acreage. Our staff in Houston has done a great job of working the total asset base as they have rigs running not only on the former Houston exploration properties but also at Katie and Mcdonough range field.

In Canada in the deep basin we drilled 11wells with a 100 % success rate and initial rates range from 1 million cubic feet to 7 million cubic feet per day.

We have also successfully transferred our horizontal technology to the deep basin. Our second horizontal well has tested its rates as high as 4.6 million cubic feet per day post fracture treatment. This is a significant success for this area where we have 73,000 gross acres, and this adds to our inventory of horizontal prospects in the company.

The down-spacing application for Wild River has being filed, and we expect approval on early 2009, while we always thought Wild River would be the first of the big five assets to reach full development, the down-spacing and horizontal drilling potential will allow exploitation to occur there for years to come. In the new frontier and exploration program, I'm going to start off in the Utica shale.

We have finished the drilling phase of our three wells horizontal program. As previously announced, we will complete the three wells sequentially. Everything is going as planned and we are near our original timeline for this project.

We also have Talisman well and the Utica gave us another good data point for our acreage from a vertical test.

Our deep Delilah exploratory prospect is South Louisiana is close to TD, and we have logged pay in an uphold interval, and not above the main objective.

The first well in the Deep Austin Chalk play is still drilling and is almost at the intermediate casing important. After casing points there are two laterals in the Chalk plan.

In conclusion despite the hurricanes and downstream pipeline issues everything is going as planned or even better especially our horizontal program which continues to expand based on success in a number of areas.

Let me thank you for listening today and operator we are now ready to take any questions.

Question And Answer

Operator

Thank you. [Operator Instructions]. And your first question comes from the line of Tom Gardener with Simmons & Company.

Tom Gardner - Simmons & Company International

Good afternoon gentlemen. Can you talk about your capital budget and how you go about setting that and specifically it's just typically you mentioned that you plan to live within cash flow. What price outlook are you predicating that on and with fraction of discretionary cash flow do you plan to set your budget?

H. Craig Clark - President and Chief Executive Officer

In terms of setting our budgets, we have all the business units put in their wish list, and then we basically put that in a ranking order based on rate of return and then work that rate of return within a context of lease saving operations and other required drilling. The initial CapEx budgets are set on a variety of prices with that final call being made by the Board. And so we have a CapEx budget that's in place right now for prices ranging anywhere from $6 to $8 for natural gas, NYMEX for next year. And related with the... and have the ability to go above that if conditions warrant that. But that is... that's how we do it, it's a strip ordering based on rate of return, but then with an overlay towards required drilling.

Tom Gardner - Simmons & Company International

Next one, jumping over to the Utica, you've mentioned earlier in the call that you've done corporate acquisitions in the past and certainly there are some acreage rich micro camps there in the play. Is that something you would reconsider perhaps a corporate acquisition in that area?

H. Craig Clark - President and Chief Executive Officer

Well we... I guess no comment on future acquisition, that's what we usually say, something clearly I think the science and technique give you first mover advantage, and our biggest competition out there is a large Canadian company, but I can't speak for this more and except to say that these wells are going to drill pretty fast once you commit to the development because of the shallow nature and ease from which they were drilled as a cohort. So, there might be some consolidation opportunities which we are not adverse to but I couldn't comment or speculate on any at this time.

And I think also the implied value of their acreage, we don't know if that's a real value or not to as many of the cash deals gone up there. So, I think we want to wait to see the play... play out a little bit and this place you're going to take capital and we are the operator and we're going to [indiscernible] and it's up to those juniors to keep up and we will see what transpires there.

Tom Gardner - Simmons & Company International

I understand. Hey, one last housekeeping question, your crude oil looked to be down a bit in the quarter, can you discus the drivers behind this decline, and what the fourth quarter outlook might be.

H. Craig Clark - President and Chief Executive Officer

You're talking of realizations?

Tom Gardner - Simmons & Company International

No, production volumes on the oil, quarter-over-quarter?

H. Craig Clark - President and Chief Executive Officer

It comes from NDL because during the month of September post Ike. We hope to process, remember roughly half our liquids are from natural gas liquids and a lot of that converted over to wet gas or could not be done. It could be also crude because the only fields that we had I'd say are prolonged shutting, I'd say prolong meaning, you couldn't turn them on after Ike flew by. What we saw at South Louisiana shut in for Gustav and never came back on for Ike and fields like Sadditi [ph] Island and White Lake and most of our South Louisiana is all oil fields. So I would say that our Mcfe was more oil than gas in the Hurricane pipeline which was in Denver.

David H. Keyte - Executive Vice President and Chief Financial Officer

We also had little pipeline disruption, and it was White Lake which curtailed oil production even free hurricane. And West White Lake is significant oil producer for us.

Tom Gardner - Simmons & Company International

And what was the curtailment at the While Lake driven by again, sorry?

H. Craig Clark - President and Chief Executive Officer

We had little pipeline curtailment because they were doing maintenance on a pipeline which restricted oil production slightly.

Tom Gardner - Simmons & Company International

Okay. Got you. Well, thank you very much, gentleman.

H. Craig Clark - President and Chief Executive Officer

And Tom, you're aware that only opposed to storm the inter coastal were closed due to barging used to ship channel Houston and all our crew in South Louisiana typically is transported by barge, so that's probably it.

Tom Gardner - Simmons & Company International

I got it. Thank you, and thank you once again.

Operator

Your next question will come from the line of Gil Yang, with Citi Investment.

Gil Yang - Citigroup

Good afternoon everyone.

H. Craig Clark - President and Chief Executive Officer

Hi Gil.

Gil Yang - Citigroup

I wanted to, J.C. you went through a long list of very impressive well results. I wanted to just maybe talk about a couple of those initially. The vertical wells in the Haynesville just to be clear, the 4.4, the 1.4 to 4.4 range that you sided, is that just from the Haynesville or is it that... was gone.

J.C. Ridens - Executive Vice President and Chief Operating Officer

We had our best well which was 4.4 which was Haynesville alone.

Gil Yang - Citigroup

Okay.

J.C. Ridens - Executive Vice President and Chief Operating Officer

Rest of those are a mixture of Haynesville standalone and Haynesville Cotton Valley co-mingles. And if you will recall earlier we talked about one of the big advantages that we've got here in vertical well is that we still have all the uphold potential. Now most of these wells were gathered or drilled to gather data on the Haynesville and to protect not with the idea that we were going to make this a pure economic plan of vertical sense but to set us up for our Horizontal program later as we gathered some geotechnical data and protected our leasehold.

Gil Yang - Citigroup

Okay, is the 4.4 in that mix that same well, or is another well that's 4.4?

J.C. Ridens - Executive Vice President and Chief Operating Officer

No, Gil, there is one standalone Haynesville vertical well that is 0.4 million a day for an IP and as I said earlier that well has performed very well subsequently. And so we have not seen a steep decline that you would associate with the Cotton valley well which makes it one of the best vertical wells that we have drilled in any zone since we have been in East Texas.

H. Craig Clark - President and Chief Executive Officer

Okay, we did not have any dry holes in the Haynesville or wells that didn't produce. But in some of things we had to co-mingle because we already had parts open and that's the reason for the co-mingling versus the Grass Root well that was the best well.

Gil Yang - Citigroup

Okay and then my question is, is that 4.4 million Haynesville well the same as that 4.4 million you grouped in the first that range of 1.4 to 4.4?

H. Craig Clark - President and Chief Executive Officer

That's it Gil.

Gil Yang - Citigroup

Okay, do you have any... would you hazard to guess as to how big these wells would be given the successes that they were horizontal, is it multiplying by 5 or 3 the right number to look at?

H. Craig Clark - President and Chief Executive Officer

I wouldn't hazard a guess on this at this point. I will tell you that we have looked around quite vertical wells that produced and then had horizontal to offset them and it is been a staggering increase but I don't know if that's going to apply to this area. But certainly it encourages us when we have seen what some of those increases have been.

Gil Yang - Citigroup

What have you seen on average?

H. Craig Clark - President and Chief Executive Officer

We've seen some things that have been vertically completed for 200 Mcf to 300 Mcf per day that have been completed in a horizontal offset that add up to 5 million to 10 million a day.

David H. Keyte - Executive Vice President and Chief Financial Officer

Can't use our good old 3 to 1 but we don't have the... I would say as an industry the good data base because of the rates being wide, kind like Haley was years ago Gil, for the range would be wide. So when we drill deep well we're looking for our 4B type target Haynesville which is based on a 20% recovery factor and that corresponds to initial rate of about 6 million to 7 million a day on that.

H. Craig Clark - President and Chief Executive Officer

That's right.

Gil Yang - Citigroup

Okay the... in general I want to ask you question about the other one but in general are the successful well results coming at an additional cost, are you doing something differently or is it just that you are just trying to hit really good wells for some reason?

H. Craig Clark - President and Chief Executive Officer

What are you talking about Gil.

Gil Yang - Citigroup

I mean in general, you just went through a lot of different areas where you'd have hit some of the best wells. Are you doing something differently in each of those areas or is there something else going on?

H. Craig Clark - President and Chief Executive Officer

Well I think that one of the things that it features with the experience that we have got in all these areas, we're getting better at what we're doing because we're optimizing fracs continuously and we're picking better locations because of the extensive database that we have already got.

Gil Yang - Citigroup

Okay.

H. Craig Clark - President and Chief Executive Officer

And particularly when you talk about the horizontal wells though, I think that we're getting better at what we do in those because we're adding stages of frac on a lot of these as we've gone through it, because we found it on the science as how close can you put these fracs together without interfering, and certainly that's up in the horizontal

Gil Yang - Citigroup

Okay. And so, is there an incremental cost to this in general?

H. Craig Clark - President and Chief Executive Officer

Well, there is a incremental cost if we are adding stages of frac in the horizontals. But, when you look at what some of these wells are asking for, I think that we more than make that up in the net present value since these vertical wells, there is no incremental cost on those.

Gil Yang - Citigroup

All right. And then last question along these line then, you haven't talked to the Barnett Shale in a while, is there ... are you not having great results there, or is it just that it's not quite mature enough to get excited about?

H. Craig Clark - President and Chief Executive Officer

Well, I think that one of the reasons that we haven't talked about it is even though we drilled our best well to-date out there, which was a little over 4 million of days as Craig said earlier, one of the things there is that we do not have the levels of activity in the Barnett than we've had in another areas. It gives us the critical mass to follow-up on things with. So, we've only had one rig running in the Barnett compared to running eight rigs in East Texas or running up to 12 rigs in Buffalo Wallow. So, we just focus on the impact play at this time.

Gil Yang - Citigroup

And then just, is it because of the economics that you don't have as many of rigs running there or, why is... or the volume of the inventory?

David H. Keyte - Executive Vice President and Chief Financial Officer

No, initially, we had a partner transition in the East side. We have to wait for that partner to close their whatever merger, so we waited on that and then that's only 50% working interest net before us. And so we've actually tried to focus on stuff where we had a 100% working interest, it's not the economics.

Gil Yang - Citigroup

Okay, got you. All right, thanks.

Operator

[Operator Instructions]. Your next question will come from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

Thank you and good afternoon.

H. Craig Clark - President and Chief Executive Officer

Hi, Brian.

Brian Singer - Goldman Sachs

In March, you shifted your strategy to spend above your cash flow for a higher growth rate versus having previously spent less than your cash flow. Question is, should we view how you are looking at 2009 spending, by spending within your cash flow as temporary. And if so, are you looking more towards the recovery of credit markets or an improvements in commodity prices to potentially increase your budget as we move through the year?

H. Craig Clark - President and Chief Executive Officer

Brian, it's what we said on April 1st, we're going to sell asset to fund our three year program with overspending. We are starting it after one year of assets sales. So we are going to be on hold until at least we get our asset sales done whenever that may happen, and then we'll evaluate at that time. I think that what we've shown is we can absolutely operate at that level given that environment it's a little more normal than things are today.

So I think we'll definitely not increase our CapEx spend beyond cash flow until we get our assets sales completed whenever that is and at that time we'll take a look around and see what the environment looks like.

Brian Singer - Goldman Sachs

Great,thank you.

H. Craig Clark - President and Chief Executive Officer

We have always keeping a pretty [ph] distance in cash flow.

Brian Singer - Goldman Sachs

Thanks. Secondly, you've historically done corporate acquisitions as failed auctions or distressed properties just wanted to get your thoughts on the current environment and whether you'd not selling assets and buying assets to make some sense at some point?

J.C. Ridens - Executive Vice President and Chief Operating Officer

Well our asset sales had a upgrade purpose order this year which is consistent with what we did for some of the big divestitures the previous years and there's a lot on non-operated in at least part of packages. So that's... we still view that as an upgrade which we'll push forward to that and we don't get it closed with one; we got the plan B for people who also bid on that.

The biggest threat was to get the properties moving out of the door is the buyers liquidity and having the ability to close in a family manner. The properties take a long because of their long lost properties typically. On the buyer side, we thought we'd see properties early this year. We did not see as much. About mid-year the gate opened and we saw a lot more. We took advantage of buying our neighbor in Buffalo Wallow. And we're seeing a lot a of bias today opportunities which is another reason to move on with the divestures you draw powder but there's a lot of activity in A and B despite the liquidity issues.

And I would say there are lot of sellers not many buyers. And I think that right now the buyers are limited to private equity and because of that it's going to a very small size which is going to work in that environment.

It's going to hard to get big packages off. The small stuff, it's still got quite a bit of activity it's... I would say the 0.5 billion to 1 billion plus such stuff it doesn't have a lot of activity these days but the small stuff there's still quite a bit of activity.

Brian Singer - Goldman Sachs

Great, thank you.

Operator

Your next question will come from the line of Andrew Coleman with UBS.

Andrew Coleman - UBS

Good afternoon folks.

H. Craig Clark - President and Chief Executive Officer

Hey Andrew.

Andrew Coleman - UBS

I just had a couple of questions. One, you mentioned you had 47 rigs running at one point in the third quarter. Could you give kind of a breakdown as to about what reasons those were in?

H. Craig Clark - President and Chief Executive Officer

I can kind of rough it out for you with my math. It is, I believe they were roughly a dozen in western, which is primarily Permian and the Texas Panhandle, we had none in the Rockies; these are operated. We had all three or four in Canada and that's in the Deep basin, and we had about 17 or 18 in eastern, which is the Ark-La-Tex. We had about 10 in southern, and then we had the one Quebec we are in. That will come up to around 46, 47 rigs and now we're down around to about 40.

Andrew Coleman - UBS

Okay. And the Lantern rigs are... those are included in that number, right?

H. Craig Clark - President and Chief Executive Officer

That is correct.

Andrew Coleman - UBS

Okay. With the potential pullback herein in rigs and their it's across the sector. How do you, I guess, utilize that the Lantern fleet than better do that, does it provide extra competition then, or is it something that you would then look at as a margin and then consider laying down some of those rig?

H. Craig Clark - President and Chief Executive Officer

No.

J.C. Ridens - Executive Vice President and Chief Operating Officer

No. The Lantern rigs typically are our best performing rigs, so those would be the last rigs we would send home. We find that our Lantern rigs performed extremely well in every area that we've got in them. Do they provide extra competition, you bet. They provide extra competition not only on a price point but also on an efficiency point. So, it gives us a great call in the field to compare to and use that as a base line for other contracts.

H. Craig Clark - President and Chief Executive Officer

When we put that fleet together, although it came in an acquisition initially we've catered that fleet for two years to our activity. Almost recently were the addition of the 1500 horse rigs, which works in the Panhandle and Haynesville. So, that fleet was designed for our activity and we sprinkled the rigs about from a price initially in the Permian. So, it's been catered to us; it works almost exclusively for us and it's been a distinct advantage throughout this period of time without dragging after the best rig we use. Those would be the last rig to lay down.

Andrew Coleman - UBS

Okay. All right, and then just... I want to stay back one more second to the commingling there at the Haynesville and Cotton Valley. I guess, what hurdle do you have to go to I guess before that would be a wise resolution and have you seen any sort of compatibility issues... I'm sure there are pressured [ph] right now that would have to be sorted out. So, that is what I want... just to understand how you would go about doing that on a larger scale?

H. Craig Clark - President and Chief Executive Officer

Well, in any area that allows for commingling, of course we can do that in the vertical wells, pretty darn in sands. Have we seen any issues with commingled fluids, no, we have not. One of the things that we've got is yes, there is a pressure differential and the higher pressured Haynesville wells particularly the standalone vertical we have to look at having in a larger scale a... not a commingle gathering system but a high pressure standalone system so we don't start knocking Cotton Valley wells off.

I think that as we move forward with of course Apple program and we bring on the higher pressure Hayesville wells, there will come a point in time when at that pressure drops and we get closer towards the Cotton Valley pressure will be, we can look at co-mingling that then and that go into the low pressure systems. I don't think that from a fluid compatibility standpoint there will never be an issue.

Andrew Coleman - UBS

Okay. Thank you.

Operator

You next question will come from the line Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets

Gentlemen, good morning.

H. Craig Clark - President and Chief Executive Officer

Hi, Dan.

Dan McSpirit - BMO Capital Markets

How much production history will you need from your first series of Utica Shale horizontals to conclude or confirm per well EURs and then larger picture the 4 plus Tcf of net resource potential?

H. Craig Clark - President and Chief Executive Officer

I would say that we're going to have to have several funds of production out of these first horizontals in order to start gauging anything about expected EURs. And as far as what that will mean in 2009, we're going to continue with another program where we will be testing some different spots in the Utica, getting some additional data points from those wells as well. And now we got 10-year lease is up there, so we're in no great rush to go out and get into a mad drilling race. So we've got the luxury of time on this while we gather that data.

J.C. Ridens - Executive Vice President and Chief Operating Officer

Dan, there is pipelines up there accessible to not all but some of the locations easily although all of them have pipelines nearby, it would be our hope to get some of these enter the sales line so we can produce at the same time.

Dan McSpirit - BMO Capital Markets

Got it. And then in light of your success in the Cotton Valley and the horizontal well drilling program there, how does that rank in terms of economics versus the Utica and the Haynesville shale plays recognizing of course the limited or non-existent production history from the Utica and the Haynesville?

H. Craig Clark - President and Chief Executive Officer

Who's trying to tell right now but the one thing that we can reference is what the economics on the horizontal Cotton Valley look like and of course they are stellar.

Dan McSpirit - BMO Capital Markets

Right.

H. Craig Clark - President and Chief Executive Officer

As we add more data those will be put in the hopper with everything else for Utica and the Haynesville and we'll see what falls out in terms of having the best rates of return.

J.C. Ridens - Executive Vice President and Chief Operating Officer

We will have to make the comment that on the Haynesville if you have this shale rights you obviously will get a better return because you get sort of two wells in one. If you have the shale rights like in the Cotton Valley Sand and we do.

Dan McSpirit - BMO Capital Markets

And do you --

J.C. Ridens - Executive Vice President and Chief Operating Officer

We are just public about that. Secondly, when you're drilling verticals or horizontal tight gas sands and you're not experiencing some of the costs for these land or seismic or the completions on shale I feel very strongly that you have the ability in this environment to cut cost more on a regular real tight gas sand well and maybe possibly on a shale well where we're still trying to figure it out.

Dan McSpirit - BMO Capital Markets

Got it, got it. And one last question if I could, on the two to three horizontal Haynesville Shale wells that you will drill and potentially complete by the end this year, could you comment at all on the lateral lengths, on the designs, completion designs of those two to three horizontal wells and how much they may vary and how much you may in fact experiment?

H. Craig Clark - President and Chief Executive Officer

Our target is to drill about 3,000 foot laterals, and we're going to do about six stages of frac on each of those, and then we'll see how effective we think that that is and to keep in a point of reference, I think it's important to revisit the horizontal program that we started in the Cotton Valley. We started off there with fewer stages of frac and then we gradually expanded that.

So I think for the first two or three wells we'll stay pretty consistent. We're trying to get about six stages of frac and see how those wells perform and then see if we can increase that... the density of frac or if it needs.

Dan McSpirit - BMO Capital Markets

Got it, thank you.

Operator

Your next question will come from line of David Tameron with Wachovia.

David R. Tameron - Wachovia Securities

Good afternoon everyone.

H. Craig Clark - President and Chief Executive Officer

Hi Dave.

David R. Tameron - Wachovia Securities

Couple of questions for you. It's just... as relates J.C. question, can you give us so more detail about the Deep Basin well up in Canada. What you doing there? How many locations you think you have? Just, just some more color around it.

H. Craig Clark - President and Chief Executive Officer

Dave I can't really comment much further than that because of some competitive reasons. All I can tell you is it is a tight gas sand zones that is produced vertically but is never been taken horizontally on our acreage areas and we are very encouraged by what we've seen so far. I think that one of the beauties that we've got there as we've got production history from a number of zones vertically. And so we've been able to compare that with what we can do horizontally and I think that we're going to have some pretty good running around. That's about all I can say about it.

J.C. Ridens - Executive Vice President and Chief Operating Officer

Our acreage is about 70,000 acres in the Deep Basin area.

H. Craig Clark - President and Chief Executive Officer

I think...another thing that you can probably say it's not the primary verticals we have been producing [ph].

J.C. Ridens - Executive Vice President and Chief Operating Officer

No, and that is true.

David R. Tameron - Wachovia Securities

And renew the operator on this well, correct?

H. Craig Clark - President and Chief Executive Officer

Absolutely.

David R. Tameron - Wachovia Securities

Any well costs?

David H. Keyte - Executive Vice President and Chief Financial Officer

I believe it was about $4 million.

David R. Tameron - Wachovia Securities

All right. Okay. That's good. Thanks, that helps. It's... and going back to Haynesville one more time. Anything we can read into PVA announced the well on a Texas side? And there is some chat around the market about maybe Texas as good as Louisiana. You guys care to comment on that at all?

H. Craig Clark - President and Chief Executive Officer

Well the first well was bore in Louisiana and I think they get a disproportion amount of the press and because that's where the first well was drilled. Most of our activity, not all of it, but most of it is in East Texas and you can see this on our map. I think maybe the news that has reach might be a little slower in coming because of competitive reasons but also East Texas in my opinion has a lot more held production acreage.

So you really got to work around on existing shallow rides which has not been the obstacle for us because in most cases we're the shallow rights holder. I know they are trying to call the sweet spot already; I think it's too early but based on what Virginia has done near us, I don't see any differences in the wealth.

David R. Tameron - Wachovia Securities

So you want to comment your activity?

H. Craig Clark - President and Chief Executive Officer

Our activity has all been on the Texas side of the border so far and based on the geo technical information that we've done we think its going to be as good as the Louisiana sites that we have seen.

David R. Tameron - Wachovia Securities

Alright, okay, let me a couple of questions. Craig, if you look back 20-20 be in a hindsight but if you look back at the decision maybe at a Dallas kind of ramp CapEx, little bit above cash flow, how do you look at that decision now and the way we were, would you do anything different or would you have under the same set of circumstances make the same decision?

H. Craig Clark - President and Chief Executive Officer

No, since we have paid for it year-to-date, no. And then also we were able to allow to capture some as I mentioned acreage which included acreage in Canada, South Texas, and East Texas and also Haynesville acreages embedded in our budget this year. So now since we have paid for it year-to-date without any help from the divestures, I am fine with that but I think that's been a tenant all along. We would try to adjust our capital with cash flow as opposed to trying to hit some output growth target as the input. So our strategy remains the same.

David R. Tameron - Wachovia Securities

Okay and then one more question, looking out to '09 and realizing you said won't comment on it, I will ask the question any way. If I look at kind of the mid point of '08 guidance oh, I am sorry, fourth quarter guidance and that just caught 5.80 number. If I keep that flat for 2009 at 5.80, that alone get you to 11% by my math, year-over-year if you back on and in the past you guys kind of said, you are going to grow 6% to 9% if you stay within cash flow. So if I pack those same metrics assuming it's a more efficient capital base now, I can easily get to 15% plus growth for 2009 pre any asset sales?

H. Craig Clark - President and Chief Executive Officer

You're right, we are not going to comment.

David R. Tameron - Wachovia Securities

All right. And the goal is still at... let me go a different way, the goal is still 2000.... the program still delivers 6% to 9% if you stay within cash flow assuming some type of reasonable debt?

David H. Keyte - Executive Vice President and Chief Financial Officer

We're going to come out with the our plan earlier than normal this time. We're going to come out and plan before our earnings in February and we'll have a good idea then. I think the wild card that we're... we don't... I mean it's not mysterious. We've had this business plan before. It will be like that business plan again. What we don't know is how many well bores we get for the cash that we're going to be spending. And we need to get a better look on services to see if that same business model holds in this cost environment.

As a reminder, we ended the year at 7 and 70 assumption, that's not too far out from now. Also as a reminder, at the analyst conference, we did inflate our well cost assumptions since costs were trying to move up starting in April. I don't think that would be the case this year. In fact, I think they should go the other way. So you will get some juice out of well costs.

David R. Tameron - Wachovia Securities

Alright. We look forward to the guidance. Thanks.

H. Craig Clark - President and Chief Executive Officer

All right. Thanks, Dave.

Operator

Your next question will come from the line of Brian Kushner with Wyeth [ph].

Unidentified Analyst

Hey, good afternoon, guys.

H. Craig Clark - President and Chief Executive Officer

Hey, Brian.

Unidentified Analyst

Could you guys go through which asset you guys sold in the Rockies and what assets you have left, where is the main assets?

H. Craig Clark - President and Chief Executive Officer

We haven't sold anything yet. That's the one we signed for. So we're contracted to sell in the Rockies and those assets include everything except for the warm setter [ph] in the Uinta Basin. That's acreage positions we had mainly from Houston which was acreage in the Uinta and our warm setter, that's pretty much is it. And then we would have sold the same one and Nabra and Nana [ph] properties in the Rockies sprinkled about. But Uinta and warm setter would be the holdovers.

Unidentified Analyst

And when do you guys think you would do some detest out of the Uinta though?

H. Craig Clark - President and Chief Executive Officer

We had planned to do some this year, but we deferred that with gas prices and rig costs have that currently focused in '09 but we have got some option value on that. So we been watching the break come to us but either gas price needs to come down or rig prices need to come down or gas prices come up, we don't have a single rig burning in the Rockies for sometime now.

Unidentified Analyst

And then let me repeat again you are going from 47, you are now at 40, what did you think your rig count would be like first quarter next year?

H. Craig Clark - President and Chief Executive Officer

I think first quarter this year was just kind of a run rate we been through. If I remember my first quarter we were around 33 rigs, so I said 30 to 35.

Unidentified Analyst

Okay.

H. Craig Clark - President and Chief Executive Officer

And that would drop about seven or eight more from the current fleet and that's also based on efficiency, not just capital cuts, pick the least efficient rig and simplify.

Unidentified Analyst

Go you. And should, could you do some formula what that means for by region?

David H. Keyte - Executive Vice President and Chief Financial Officer

You mean in terms of the rig count by regions?

Unidentified Analyst

Yeah, using that 30 to 35.

David H. Keyte - Executive Vice President and Chief Financial Officer

Yes, it is a little bit at the 40 right now. You're going to be about I would say 9 or 10 rigs in Western, there are going to be a couple in Canada, you will be about 15, 14 or 15 in Eastern, and there will be about 8 in Southern that will be pretty close.

Unidentified Analyst

Okay.

David H. Keyte - Executive Vice President and Chief Financial Officer

Right now we're at 40 today and I can break that out for you exactly. Western is 11, Canada is 2, Eastern 17 which includes the Arkoma and East Texas, Southern is 10, and the rig in Quebec has obviously been done so there is no new ventures activity.

Unidentified Analyst

All right.

David H. Keyte - Executive Vice President and Chief Financial Officer

Could be 40, so its going to be kind of across the Board. I think we targeted 8, so we took 8 of 40 it would be roughly 32.

Unidentified Analyst

Okay. That's exactly what I needed, thank you, guys.

H. Craig Clark - President and Chief Executive Officer

All right, thank you.

Operator

And at this time there are no further questions. Mr. Keyte are there any closing remarks?

David H. Keyte - Executive Vice President and Chief Financial Officer

No, this concludes our conference call, and thanks everybody for your interest, participation. Any further questions give us a shout, thanks.

Operator

Ladies and gentlemen, this does conclude the Forrest Oil Corporation third quarter earnings teleconference. You may now disconnect. .

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Source: Forest Oil Corp. Q3 2008 Earnings Call Transcript
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