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Forest Oil (NYSE:FST)

Q1 2010 Earnings Call

May 04, 2010 2:00 pm ET

Executives

H. Clark - Chief Executive Officer, President, Director and Member of Executive Committee

John Ridens - Chief Operating Officer and Executive Vice President

Michael Kennedy - Chief Financial Officer and Executive Vice President

Patrick Redmond - Vice President of Corporate Planning and Investor Relations

Analysts

Biju Perincheril - Jefferies & Company, Inc.

Jeffrey Robertson - Barclays Capital

Brian Kuzma - JP Morgan

Dan McSpirit - BMO Capital Markets U.S.

John Fitzgerald - Raymond James

Gil Yang - BofA Merrill Lynch

David Tameron - Wells Fargo Securities, LLC

Anuj Sharma

David Kistler - Simmons & Company

Scott Hanold - RBC Capital Markets Corporation

Brian Singer - Goldman Sachs Group Inc.

Operator

Good afternoon, ladies and gentlemen. My name is Sarah, and I will be your conference operator today. At this time, I would like to welcome everyone to the First Quarter 2010 Earnings Conference Call. [Operator Instructions] Thank you. Mr. Redmond, you may begin your conference.

Patrick Redmond

Thank you, and good afternoon. I want to thank you for participating in our First Quarter 2010 Earnings Conference Call. I will note that a replay of this conference call will be available through May 18, as described in our press release issued yesterday. We have joining us today, Craig Clark, President and CEO; Michael Kennedy, Executive Vice President and CFO; and J.C. Ridens, Executive Vice President and COO.

Some of the presenters today will reference certain non-GAAP financial measures, regularly used by Forest in measuring its financial performance. Reconciliation of such non-GAAP financial measures with the most comparable financial measure calculated in accordance with GAAP are available on our website and can be viewed by clicking on the Investor Relations tab, then non-GAAP at www.forestoil.com.

In addition, 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 Forest expects, assumes, plans, believes, budgets, forecasts, projects, estimates, anticipates, et cetera, 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 Michael Kennedy. Thank you.

Michael Kennedy

Thanks, Pat, and thanks, everyone for joining us on a busy earnings day. The first quarter of 2010 marked Forest Oil's return to organic growth as production pro forma for divestitures was up 1% sequentially to $417 million per day. This was achieved despite selling $3 million a day of non-core properties in Canada during the quarter. Production exceeded our guidance of $412 million a day and has positive momentum due to our excellent results in the Texas Panhandle. These results have also led us to update our guidance to reflect an increase of liquids component of our production mix up to 22.5%.

Realizations also were positive as natural gas came in at $0.43 per Mcfe differential. Oil came in at a $4.63 per barrel differential, and we realized 51% of WTI for our NGLs. Due to our favorable marketing contracts, we have increased the guidance for our NGL pricing to 42.5% of WTI.

Production expense for the quarter came in below the midpoint of guidance at $1.21 per Mcfe. This line item continues to impress as our cost-cutting initiatives have us firmly entrenched as a low cost producer. Cash, G&A expense for the quarter decreased sequentially, $0.06 per Mcfe to $0.36 per Mcfe. We have increased our guidance by $5 million related to G&A expense, taking into account our comp expense related to our increased activity. But we remain in the low end of our peer group at approximately $0.31 per Mcfe for the year.

DD&A expense came in higher than our guided range at $1.39 per Mcfe, as increased service cost pressured our future development costs, and the strengthened Canadian dollar resulted in an increase in our Canadian business unit cost. We have increased our DD&A guidance to incorporate these two items.

Our E&D capital expenditures of $216 million was, as expected, disproportionately weighted towards the first quarter as our activity in Canada has performed in the winter months before the spring breakup. We are running up to seven rigs during the quarter in Canada. Whereas currently, we're not running any rigs during breakup.

We also invested $63 million in acreage, adding acreage in all the three core areas and adding to our significant Eagle Ford Shale position. Our balance sheet remained strong during the quarter. Forest's borrowing base was reaffirmed in April of 2010 at $1.3 billion, and we have over $200 million in cash, which results in liquidity in excess of $1.5 billion.

Net debt increased by approximately $100 million during the quarter as the accelerated CapEx in Canada, the acreage acquisitions and the cash tax payment of $63 million related to the gain on our 2009 Permian sale exceeded our discretionary cash flow.

In order to adhere to our strategy of maintaining a strong balance sheet, Forest announced at our analyst conference in March of 2010, divestiture program of $150 million, and we are making progress towards that goal. We have started the process of selling our East Texas midstream assets and have sold an additional $17 million Canadian properties in April of 2010. The divestiture program should bridge any gap between our capital program and discretionary cash flow in 2010.

In summary, the first quarter of 2010 marked the return of organic growth with significant momentum generated toward meeting our double-digit organic growth guidance. This should be achieved without adding any leverage to the balance sheet and maintaining our excellent liquidity position. In my mind, this qualifies as a successful and sustainable business plan.

With that, I will turn it over to Craig.

H. Clark

Okay. Thanks, Mike. Good summary, and thanks to everyone listening today. The first quarter of 2010 was pretty much right down in the middle of the fairway, as Mike referred, and ahead of guidance in terms of production and operating cost. It was kind of a fun quarter in some regard because we're now able to provide details from our analyst conference, or as a result of the conference, for the potential of some of our main core assets, particularly in the Panhandle and the Canada Deep Basin. You can also begin to see in this quarter not only the quality of the assets, but also the growth potential that this company now possesses.

The major highlight for the quarter is got to be the Texas Panhandle horizontal program that J.C. will go into. We continues to far exceed our pre-drill expectations. Most people know me to be pretty conservative, so this may be the most optimistic you'll ever see me. I cannot emphasize this enough. The Western business unit has now replaced the sale of our Permian production in only one quarter. The liquids production has already risen to just near 10,000 barrels per day, and Canada has quietly [ph] (14:27) replaced the production they sold last year in early this year, pretty amazing.

The second major highlight has to be the addition of significant acreage in our main plays at affordable prices. We've added year-to-date, 82,000 gross and 60,000 net acres since the end of last year at an average price of $1,200 per acre. This does include acreage in the core Panhandle and Deep Basin areas, plus I guess the hot areas like Haynesville/Bossier and now in the Eagle Ford. In fact, our total acreage position in shale play now totals just under 600,000 net acres in the Eagle Ford, Haynesville, Utica and Horn River.

We've seen deals by offset operators in recent weeks that price Haynesville/Bossier and Eagle Ford acreage at $10,000 to $15,000 an acre depending on how you calculate it. Furthermore, when we added their interval as a successful horizontal candidate in the Panhandle, it's like multiplying the locations or the acreage by two or threefold, so we've got a lot more running room there based on the well J.C. will discuss.

I should also mention that we are seeing good offset competitor data points from the Texas Panhandle, the Texas Haynesville/Bossier, even the Texas Cotton Valley and now in the Canada Deep Basin and the cores offset to us in the Eagle Ford oil, which further validate the positions. Yet I keep getting and asked question about the repeatability in places like the Panhandle and Deep Basin. I hope these questions have already been answered.

We closed another, Mike referred to, the new sales year-to-date $29 million in property sales, $12 million in the first quarter, $17 million just after the end of the first quarter. So with our non-operated property sales, mainly in Canada since last year, we essentially traded non-core properties for proceeds to buy the aforementioned acreage in places like the Eagle Ford, where we operate at 100% working interest. A pretty good trade based on recent shale data acreage points, I think.

Our last major highlight, and I'll talk about it in more detail, is the reallocation of capital to the Granite Wash, or Texas Panhandle, away from other gas-prone plays. This allocation is based on results and validation. It's also based on service cost as much as natural gas prices currently.

While I'm talking about capital allocation, I'll talk about first, the first quarter 2010 capital program. We ran an average of around 21 operated rigs during the quarter. Most of the rigs were added in the first quarter, so you get your ramp up during the quarter and your production ramp up subsequently after that in the quarters.

The operated rigs, mostly Lantern Company [Lantern Drilling] rigs, except for Canada, we deployed as follows: we had four in the Panhandle, five in the Ark-La-Tex, five in South Texas, seven in Canada. There were also six non-operated rigs running during the first quarter. Mostly of the non-operated were in the Panhandle and you read about some of those in other people's releases.

We spent $260 million in E&D CapEx in the first quarter, drilling 71 gross wells at a 100% success rate, so we completed them all. Of the 71 gross wells, 39 of them were horizontal or directional. And of course, the capital on those wells were more because they were horizontal as much as 75%. So clearly, we're in a horizontal program.

The first quarter CapEx did include, as Mike mentioned, $63 million in new leasehold that is not including the Eagle Ford that was done last year. Our spending is ahead of guidance simply for the fact that we have an active leasehold program and the high-winter activity in Canada, which pretty much equals out about mid-year with the Canada road bans. So the current rig count, I guess, for the second quarter would be 12 operated rigs by dropping the Canadian rigs for the quarter and losing a few in Eastern and Southern in favor of the Panhandle, so there you have it.

We did see some cost inflation as we predicted back in January, maybe even more than we predicted, mainly from the services we predicted: pumping services or fracs, proppant, pipe and directional drilling. However, the industry experienced what I've termed micro inflation or regional inflation, specifically in East Texas, North Louisiana sponsored by industry holding on to their Haynesville/Bossier leases. On a side note, I guess it's important for any management to understand the risk or challenges underneath organization, so we were able to go directly to the field several weeks ago, and saw intense inflationary pressure on fracs and associated services as much as 30%.

In part, because of that inflation, we moved the capital out of the area into the Texas Panhandle. We saw limited cost pressure in the other areas except for a 13% increase in the Canadian dollar exchange rate. We also reallocated some CapEx from other dry gas projects to the Eagle Ford leasehold. The reallocation will add four gross wells in the Panhandle with the additional rig. In fact, it's our rig, and then two wells in the Eagle Ford.

Again as a reminder, we started running $5 gas and $60 NYMEX crude entering 2010. So we're really not far off our plan as we started in January. I don't think anyone, however, would argue with more Panhandle activity. While I'm on the cost side, again, you should compliment our focus on reducing cost, reduce gas cost, operating cost by 20% or more which is the Permian. And also, we completely offset in small G&A, but also the interest expense. Certainly, we're seeing benefits in all of our resource plays for overall cost focus and being a low-cost provider. We're also kind of cheapskates on leasehold prices or acreage.

On the production side, our average of 417 a day is up. The equivalent today is up from last quarter despite selling, as Mike said, 3 million of the remaining non-operated Canada the properties that we identified late last year. The pretty solid results, I guess, coming out of what would be a rough winter weather season for snowing weather. The Texas Panhandle and Canada Deep Basin carried the mail [ph] (20:51) and Canada has 25 to 30 million a day now net shut-in equivalents still to come on this year. So their organic growth and record production in Canada is simply behind the wellhead valve.

We closed an additional 2 million a day of properties, as Mike mentioned, for $17 million in April 2010. So we sold 5 million a day to date, leaving guidance the same, but we sold 5 million a day. However, we leave our production guidance unchanged as I mentioned, so you can see the strength of the program.

Our data room is open for the midstream East Texas pipeline, subsidiary is very active. So everything is going according to plan so far this year, including our assumptions of cost, et cetera. I like where we're positioned in terms of the results of the portfolio. You have to have a portfolio, so you can have capital allocation. Otherwise, there isn't any, and I like our flexibility going forward. This includes no long-term drilling contracts and only limited short-term lease obligations.

Now I'll turn it over to J.C. for some pretty nice well results.

John Ridens

Thank you, Craig. We continue to have a very successful horizontal drilling program in the Granite Wash, setting a new record with our eight well in which we have 100% working interest achieved in an IP of 45 million cubic feet equivalent per day. This is the best well we have drilled to date in the play and importantly, comes from an interval that we have not previously tested horizontally. This well produce an excess of 5,000 barrels of liquids per day, a little over 3,000 barrels of condensate and about 2,000 barrels of NGLs per day. Added to this was over 14 million cubic feet per day of residue gas. This is a stellar result for our program, especially as it opens up an additional interval for exploitation.

We break out all the component of our production stream because that's how we get paid. When we have contract to provide for NGL volumes to be fractionated, we quote those volumes as well as the shrunk gas. The NGL stream provides a significant uplift in value as we showed in our analyst conference compared to an unprocessed stream. In fact, 2,000 barrels of NGLs currently represent approximately $56,000 per day of additional income for this well. We provide this detail not to confuse humanity, but to demonstrate the significant value our marketing contracts provide as the upgrade for NGLs was $7.94 per MMBtu, compared to $4 per MMBtu for natural gas as of April 1, 2010. Of course, you have to have a sales contract that provides for this.

Our ninth well is pretty darn good too, yielding an IP of 24 million cubic feet equivalent per day, 63% of which was liquids. Our working interest in this well is almost 94%. So these two wells gave us a significant add to net production in April. Both wells were 4,300-foot laterals completed with 10 frac stages.

We have four wells in various stages of drilling right now. Our 10th horizontal Granite Wash well is currently being completed, and this well is located in Hemphill County and was drilled to further expand the Granite Wash play.

In summary, we have extended the play not only vertically now by the addition of the new zone, but also extended the geographic extent of the play by drilling in Hemphill County. With our horizontal program averaging 29 million cubic feet equivalent per day for initial rates, 60% of which is liquids, we are reallocating capital to add another rig to the play, bringing our total horizontal Granite Wash program to five operated rigs. We've also added about 3,000 acres in new land in the Panhandle during the last quarter, once again, additional running room.

The Granite Wash isn't the only play in which we continue to see repeated success though. In the Nikanassin play in our Canadian business unit, we completed our 11th and 12th wells with average IPs of 10 million cubic feet per day. We ended the winter drilling season with two additional wells drilled and cased in the play that will be completed after spring breakup.

We also added an additional 15,000 net acres to this position in April, bringing our total position in the area now to 79,000 net acres. We have approximately 25 to 30 million cubic feet per day of production that is currently shut-in pending completion of infrastructure projects. Assuming the approval of the necessary permitting, these projects should be completed in the third quarter with sales commencing on the fourth quarter.

In our EB horizontal oil program, our winter drilling campaign, resulted in increasing oil production from the field by about 900 net barrels per day. With robust oil prices and the royalty and drilling incentives provided by the province of Alberta, the rates of return for this project are outstanding, approaching 100%.

In our Haynesville/Bossier program, we added almost 17,000 net acres of land in the core during the first quarter. This increases our core acreage to almost 28,000 net acres. We currently have two wells pending completion in Red River Parish. In addition to our operated activity, we participated in two outside operated wells completed in the first quarter for average initial rates of 22 million cubic feet per day. We have four rigs drilling, two in Woodardville Field in Red River Parish and two drilling in the Sabine Parish portion of the Bossier. As we have stated previously, the majority of our drilling this year is to hold leases, and we will have almost all of our land held in this play by the end of 2010.

We've also announced the addition of 106,000 gross and 102,000 net acres in the Eagle Ford. Our acreage is concentrated in Gonzalez and Wilson counties, where we expect the Eagle Ford to be in the oil window. Our Gonzalez and Wilson County acreage offsets the EOG acreage that they highlighted at the recent analyst day. Acquisition of 3D seismic is slated for this area with acquisition expected to be complete by the end of the third quarter. We acquired the bulk of this position during 2009 with prices of less than $500 per acre, so our cost of entry fits our model of getting large positions early in the cycle of the play inexpensively. This position not only has Eagle Ford potential, but also has additional horizontal potential in shallower formations such as the Austin Chalk.

In summary, our horizontal programs across the company continue to provide excellent results. Our liquids production continues to increase. Capital is being reallocated to programs with higher liquid components and our acreage acquisition program is adding quality acreage as we keep building for the future.

Operator, we are now ready for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets Corporation

The Granite Wash for 45 million a day is pretty fantastic. Can you talk about in terms of if there's anything different in the design with that well relative to some of the others length or the way you did the fracs or proppant, or does it have to do with just the reservoir itself?

John Ridens

Scott, the answer to that is same product design, same proppant, same number of stages. However, the real key to this is opening up a new interval that we have not seen tested before and getting the high reservoir quality in that interval.

Scott Hanold - RBC Capital Markets Corporation

And then, so when you do some additional drilling in the Granite Wash, is this going to be a formation that you're going to be a little bit -- you're going to target a little bit more aggressively at this point?

John Ridens

Yes.

Scott Hanold - RBC Capital Markets Corporation

And could you just remind me...

John Ridens

The addition of the fifth rig certainly comes with this interval in mind, Scott.

H. Clark

And to emphasize, Scott, that the vertical testing helps you to take these zones whether you're in this county or a county to the North. That's just a huge benefit.

Scott Hanold - RBC Capital Markets Corporation

Yes, I guess on that point then, as you guys look at some of the vertical penetrations, are there any other perspective zones out there that could have the same type of applicability that haven't been very well tested to this point horizontally?

H. Clark

Well, out of the seven Granite Wash and the tight block, I think, in the analyst conference, were up to two industry, maybe one or more but I guess the short answer is, they are all perspective depending upon on how we test vertically. And they are not just perspective in the South, it can be a perspective in the Central. And we're seeing some competitor data points that would add credence to that.

Scott Hanold - RBC Capital Markets Corporation

And just quickly, could you remind us typically how long are your laterals, how many stages you're putting in on these wells?

John Ridens

4,300-foot laterals, and 10 to 11 frac stages. Last two wells were 10, and we are completing one now with 11.

Scott Hanold - RBC Capital Markets Corporation

And the proppant?

John Ridens

White sand.

Scott Hanold - RBC Capital Markets Corporation

White sand, okay. And one last question, on the Eagle Ford, what are your near-term plans with the Eagle Ford? Are you going to -- tend to be, as you get into the back half of the year, do you tend to be a little bit more aggressive drilling that? And how long do you have -- what are your lease terms on some of that acreage?

H. Clark

They're primarily new leases. Most of them were obtained before the end of last year, so that you're not far into the clock. Some 2Ds have been dragged out there. We plan on shooting some 3D. We have done some well testing with our rigs from time to time, and we'll continue to do that, but no clear big horizontals. Those would be later in the year when we get the seismic. The offset wells would cause us to move that forward, and that's why we reallocate some capital to it. We didn't have anything in there for this year. In fact, we're going to lay low until somebody figure out where the acreage was, and it's in Southern Wilson and Gonzalez.

Scott Hanold - RBC Capital Markets Corporation

And are they three- or five-year lease terms typically on those?

H. Clark

Typically, three.

Operator

Your next question comes from the line of Dave Kistler with Simmons & Company.

David Kistler - Simmons & Company

Real quickly, just following up on Scott's comments on the Granite Wash. So just to be clear, the extra rig going to the south portion is going to be focusing on the same interval that, that 45 million a day well was on. But from your vertical penetrations, you think you're seeing the same zone up on the North?

H. Clark

Yes, let me -- we'll bring our rigs in, and so we'll have four 1,500 horse rigs in the South and Central, including Hemphill County and one to the north, and that one to the north is not that big. Any of those four, not specifically that rig, will be focused on the second zone as well as in Hemphill County in addition to Wheeler. But obviously, that zone adds to the portfolio four incremental wells in that zone. It will just depend on where the rig is as to which one drills it.

David Kistler - Simmons & Company

Okay, and so then...

H. Clark

I've seen that the net [ph] (32:52) will go up in the South. The South and Central rig is the same rig. To the North, that's not only more [indiscernible] (32:59) at the zones, and that rig continues to do that in Granite Wash, but that's a shallower program. But this zone would be in what we define as Central and South. There is actually some more data points today I believe our competitor in Hemphill. But all four of those rigs are going to bounce back and forth to the South and Central. We're just going to add four incremental wells for the zone that, that rig will make available to us when it appears on the scene.

David Kistler - Simmons & Company

And then just from a pure capital allocation standpoint, how much capital are you actually moving from the Ark-La-Tex region to the Granite Wash and Eagle Ford, et cetera?

John Ridens

For the Panhandle portion it will be about, in round numbers, $30 million. And for the Eagle Ford, probably in the neighborhood of about $6 million to $7 million for drills, not counting seismic that we have gone ahead and forecasted for that.

David Kistler - Simmons & Company

And then just thinking about the Nikanassin for a second, Your Well #10, I think at the analyst day, you were talking about having a $4.7 million cost. But previously, you talked about kind of guidance of closer to $8 million or $9 million per well. How did Wells # 11 and 12 shake out from a cost standpoint?

John Ridens

We were right on forecast for what we were thinking for cost. They're running about $8.7 million. That cost that you're probably thinking of, the $4.7 million, was for the drilling phase only. And the reason we focused on the drilling phase is because that's where we've seen the reduction in cost so far has been through reduced days spent on reaching TD. But in total, we were about $8.7 million.

David Kistler - Simmons & Company

One thing that you guys didn't mention in the release or the call was the Utica. I know you guys are in the process of doing the 3D. Still have plans to drill the well there this year? Or just given where gas prices are and the length of the lease there, do you think about reallocating that capital elsewhere?

John Ridens

No, we're still going to continue to get to the seismic acquired, and then look for another well in there late in 2010.

David Kistler - Simmons & Company

And then just last housekeeping and maybe a little bit -- and maybe, Craig, we can take it offline, but can you guys breakdown for the acreage you acquired in the respective lease areas what the costs were at Buffalo Wallow and Nikanassin and the Eagle Ford?

John Ridens

I'll take that offline. We'll give you a call and talk about that.

H. Clark

Yes, we don't [ph] (35:51) have all the detail. We averaged year-to-date $1,200 an acre. Most of the acreage was not in the Eagle Ford.

Operator

Your next question comes from the line of Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

In terms of the capital reallocation, can you talk more specifically on what types of wells you are giving up to focus more on the Granite Wash, Eagle Ford, et cetera? And to what extent there are further opportunities to do that in 2010 and then in 2011, to the extent that you've got acreage that you will have at some point hold?

H. Clark

That would be mostly dry gas, and that would be probably three tops of wells. I don't want to prejudice any area. It also has to do with the fact that when we reallocate capital, it is our rig that we move, but in no particular order. We did have some Wilcox stuff in South Texas around Katy, that's drier gas. Arkoma which is shallow, but that's dry gas. And then the Cotton Valley/Haynesville rig, that's swung back and forth, although the Haynesville rig is pretty much stay there, because of the acreage in Shelby and Sabine. But it's pretty much Cotton Valley, Arkoma and a few South Texas.

Brian Singer - Goldman Sachs Group Inc.

And is there a gas price at which you would -- otherwise you say, "We'll go back to drilling those areas and will increase our budget as opposed to shift our budget?"

H. Clark

I would think that since we run everything in five, they are actually good at five. It's capital allocations. It's also growth related, but the dry gas obviously prejudiced it. I think it provides a prejudiced price. But I'm going to tell you anything in the Ark-La-Tex area, Ala [ph] (37:55), East Texas, North Louisiana, I'm going to say the cost increases that I saw probably has as much to do with it as my perception to gas price. Clearly, however, the Panhandle receives more capital, because we just can't replicate those economics anywhere in the company, and I think some of our competitors feel the same way. But we took it from the dry gas areas, but we also took it from one area in the Ark-La-Tex where we thought we had intense cost pressure. And the example I can have is the fracs were going up 30%, and we said, "No way."

Brian Singer - Goldman Sachs Group Inc.

And lastly, in terms of additional acreage acquisition, can you talk about where you stand? And how much additional capital we could expect going forward, particularly in the Nikanassin, Eagle Ford and Granite Wash?

John Ridens

In the Nik [Nikanassin], I would say that we are pretty well done, because this last sale that was completed in April is about all of the land that was left available on what we consider to be the core. So I think that we are pretty well done on that. I would say that we are opportunistic vis-à-vis the Eagle Ford and continue to look for opportunities there. I can't give you a range because it depends upon what we find that's going to be available. Obviously, in the Panhandle, we continue to amalgamate acreage there. And we are actively seeking acreage every day, including looking to expand the play over on the Oklahoma side of the border. So if we could find enough acreage out there to go ahead and spend another $40 million, $50 million this year, I certainly recommend we do so.

H. Clark

I don't think, Brian, the pace would be $60 million a quarter. However, one of the reasons we want to stay flexible financially going into 2010 is we actually thought you'd see some acreage start falling apart, much like some of the acreage we got in Shelby County in the first quarter. And I think that phenomena gets processed, stay like they are, we'll continue to repeat itself. So I would hope to add to that position, but I don't think you'd be spending $60 million a quarter.

Operator

Our next question comes from the line of Gil Yang with Merrill Lynch.

Gil Yang - BofA Merrill Lynch

Could you comment on, sort of following on Brian's question about the reallocation of capital, does the CapEx shift away from certain areas, increase this expiration that you're going to be seeing?

John Ridens

No, because everything that we shifted, Gil, is on HBP acreage positions.

Gil Yang - BofA Merrill Lynch

And moving over to the Eagle Ford, based on the EOG's presentation and where you are, on Granite you haven't enjoy your 3D yet. But based on what you know about your area, your acreage versus what they have, what would you predict your EURs [estimated ultimate recovery] and productivity to be?

H. Clark

I don't really have one. Their numbers were pretty impressive. All we know is we abut them in some cases, and we lease that land. And I know the oil and gas win that seems to move everyday. But based on the fact that it's the source rock for other oil intervals, I would probably bet that it's oily. But clearly, we're looking for oil wells, and it's not in the deepest part of the basin like you have when you part going to South Texas. But they would be, I hope similar to their wells. But since we've done no horizontal testing at the time, I think it would be a stretch for me to speculate, except I'm very attracted to the acreage more than I was, now that I'm seeing their numbers.

Gil Yang - BofA Merrill Lynch

In Granite Wash, the Well #9 was drilled into the old formation or the new formation?

John Ridens

It's in the old formation.

Gil Yang - BofA Merrill Lynch

Okay. And just to clarify, the new formation is part of the 343 locations you talked about in your analyst presentation for the south fairway? Or is that new inventory?

John Ridens

Both, because we had some locations picked for this already. But I would say that with the success that we have seen out of this interval, it's certainly will add to it as well, Gil.

H. Clark

And our location takes, Gil, work. We're simply based on either competitor activity and ours, horizontally and vertically. If there hadn't been any of that, ARC was questioned [ph] (42:34) on vertical or hadn't been tested by some of the [ph](42:36) vertical. We did not add that. So clearly, every time we had a zone, we do add some locations.

Gil Yang - BofA Merrill Lynch

Clearly, this well is better than you expected it to be. Based on what you've been able to predict in the past and the results in this well, how confident are you that this is not just the once-off success and that it's repeatable going forward, for this new interval?

John Ridens

Very confident. The horizontal in this well was actually set up off of a vertical recompletion where we got some test data. Once again, get the science right and then do the validation. So we were very pleased with the results that we got out of the vertical recompletion, which helps set up this. In turn, very successful horizontal. And now that we've got these data points on how the well has been producing, it further increases our confidence about being able to extend this.

H. Clark

Clearly, this was higher than our mid-case. And we've assumed our mid-case in the guidance and the working interest on average. But clearly, we're also seeing competitor activity on both sides of the county line or the Oklahoma border that are of this magnitude. We saw some more today and yesterday. So my compliments is not just based not my data points, it's also based on also the operators as well. And needless to say, the competitions increased up there because of it. But this exceeds our expectations, and probably that's an understatement.

Gil Yang - BofA Merrill Lynch

Of the other five horizons you haven't drilled yet, are there other ones that are as promising as this new horizon? Or are the first and second horizons you've been drilling into is sort of the cream and the others are sort of also-rans?

John Ridens

No, I wouldn't described them as also-rans because I think that there are data points out there from competitors that point to being able to make high-rate wells in other zones. What I would say is that the zones that we have been focused on though, in our opinion, will be the highest liquid-yield zones. And so, certainly, in this market with the spread between liquids and gas prices, I think that our concentration on this level is a very prudent thing to do at this point.

H. Clark

If we have started at the bottom, we would have been in the Atoka. That's a little bit drier gas, not completely have some liquids. And it's actually got a little higher rate on gas, but it doesn't have liquids. So we targeted the fix and the liquids early on. I'm not going to rule anything out of this point, because it's so in excess of our mid-case.

Operator

Your next question comes from the line of John Fitzgerald with Raymond James.

John Fitzgerald - Raymond James

Could you talk about how many zones you completed in the Nikanassin on those 11 and 12 wells? And if there was a difference between the two?

John Ridens

John, I'd need to take that one offline because I don't really have the exact count of completion intervals. I can get that and we'll get back to you.

H. Clark

I'm going to tell you that five well was basically the Nikanassin, which explains the five our mid-case was seven, so it's below it. The 15, but that's a couple, but we're still running the seven as the mid-case. So the five and the 15, average 10, so we're fine. But I believe that one was just a straight Nikanassin test.

John Fitzgerald - Raymond James

And then on the Granite Wash, with these recent wells, do you see kind of your expectations for the central part of the play in terms of like EUR guidance in the Q? You've been talking five to six Bcf a well. Is that moving up do you think? Or is this mainly a southern fairway?

H. Clark

We seen two competitor -- actually more than that in Hemphill and saw one today that actually validates the rate. We ran the rate of IP at around 6.8, and that was actually in the analyst conference. I don't remember the reserves, but it was what we had. We start to that because of the industry average being below that, but it's also dominated by really, really, really short, in fact, almost non-existent horizontals. These last couple of wells we seen by competitors in Hemphill County, Central and South, I think we saw a 17, I think we saw a 20, and I think we saw one with another competitor yesterday that's 30. That's like outrageous, but we use 6.8 which gives you about five Bs [Bcf]. So it looks like we may need to take that up, if the average comes up. But also I think -- before it validates, the Hemphill County line is not an impenetrable geologic barrier, but so the activity obviously is moving north.

Operator

[Operator Instructions] Your next question comes from the line of Jeff Robertson with Barclays Capital.

Jeffrey Robertson - Barclays Capital

Craig or J.C., can you all talk about any liquids constraints if there are any in the Granite Wash, given the increasing level of liquids that you all have in your recent wells?

H. Clark

None so far. In fact, the last page of the Western Business Unit analyst presentation showed the capacity of the pipes. Granted, you'll need some more capacity. In fact, the Enbridge has announced some expansion, and we're partly responsible for that. So far so good, because there's obviously been more gas than capacity up in this area for some time. We've actually subscribed to some firm to get some of the stuff out of there. But we've seen no issues so far, although the fractionated strip on liquids actually declines. But that's not because of these, it's because of the arbitrage between crude and gas. If you saw any pressure, it would be on the ethane side, because that product, typically, gets rejected. I doubt if you'd see it on the propane butane side.

Jeffrey Robertson - Barclays Capital

And, Craig, when you were talking about the areas that you've added acreage, did you mention the Horn River?

H. Clark

Yes, we've got 61,000 net acres up there, right on the Territories-BC border. We've had that acreage for some time with the pipeline with it. And I didn't include in that number Barnett's or anything like that. I just took the four that I mentioned, including the Utica. But I think it's 60,000 net in the Horn River.

Operator

Your next question comes from the line of Biju Perincheril with Jefferies.

Biju Perincheril - Jefferies & Company, Inc.

On this Granite Wash wells, do you have a 30-day rate that you can disclosed?

John Ridens

We haven't gotten to 30 days yet, but I will tell you that well continues to perform at an outstanding rate. It has not fallen off significantly. And so, when we get to a 30-day rate, we'll include that in the next call.

Biju Perincheril - Jefferies & Company, Inc.

But some of the earlier wells that's been online for 30 days?

John Ridens

Yes, we quoted those in the analyst presentation, Biju. And we saw rates 15 million a day after 30 days or greater, I believe.

Biju Perincheril - Jefferies & Company, Inc.

And what was in your guidance model that you use for 30-day rates?

H. Clark

I don't know. We started them in the south at 13 million a day and decline them at a parallel, so the curve we got, in fact, the curves in the analyst conference, but I don't know that. But we parallel the decline curve of the verticals. Obviously, so this higher rate parallels it. In the analyst conference, we showed you the first four wells and we actually showed you the average rate ranging from 50 to 300 days. Those rates range from 28 million to 5 million. The five is the one that's been on for over 300 days. But I don't know the exact rate, except that, clearly, when it's higher on the IP and that stabilized into the line, not some peak rate that's flared, as into the sales. The same way we do the Haynesville. In fact, we restrict their flow to 20% drawdown. We showed the kind of the flatness of the curve, we showed -- and that's just to keep prop from flowing back safety. But I don't know the 30-day rate, but clearly, when it's higher than the 13, it's beating our curve for the 30-day as well.

Biju Perincheril - Jefferies & Company, Inc.

And then the difference on -- just can you talk about how they vary across your acreage? How do you assume in some areas, the different zones are more productive? And do you have any plans to try dual laterals or anything like that?

John Ridens

We don't have anything planned for dual lateral at this point, because our methodology would typically not be to be using serial number one of the new product. We'd like to see some -- the establishment of that by others before we would switch to that. As it pertains to the geographic distribution of these zones across the area, it varies because we do see the zones varying quite a bit going from north to south, in terms of which is going to be the major productive interval. And so as we move outside of the South area up into Hemphill, you'll see some different zones tested. You're going to see some difference zones tested down in the south fairway. Not only this well that we currently have that we're just talking about today, but additional wells that we will be ready to discuss later in the year will test intervals that we have not tested previously.

Operator

Your next question comes from the line of Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

So given the company's opportunity said today, how do you balance living within cash flow versus accelerating drilling and bringing that value forward in places like the Granite Wash and then later, the Eagle Ford Shale?

Michael Kennedy

Yes, Dan. This is Mike. As you know, one of our tenets is the 4-POINT strategies that maintained a strong balance sheet. So we're actually focused on that point as well, so we like to live within cash flow, because right now we're comfortable at our debt metrics. And the main one being proved at, total debt to a proved developed reserves. So right now and we think that growing within a double digit rate while being within cash flow is a prudent thing to do.

Dan McSpirit - BMO Capital Markets U.S.

And then lastly here, I think understanding the stack pay potential in the Granite Wash is critical to understanding the company's reserve potential and thus, its evaluation. How do you address this issue here going forward? And I guess maybe make more transparent that value?

H. Clark

We tried to in the analyst conference address, at least, the zones we know. But when you -- I hate to use an analogy, when you find another zone, you can multiply stuff by two for that given area. However, we try to emphasize that I think people are focused on the areal extent sometimes. I think they need to be more focused on the number zones that ends up. And we've had competitors talk about 15 zones and 30 zones, and I don't think that you're going to have all that in one given area. But you have that many that you can count all the way up from the north to the south. That zone delineation will be, I guess, the question mark going forward. Not the repeatability to get our mid-case, it'll be how many more of these work like that. And also I should mention, even if you have a real thin one, that's only going to give you 5 million a day. And I'm just using a round number. That's where the bill stack comes in because that could be the stack that tends. [ph] (55:30)So I think this area continues to get better. Fortunately, we've only identified the locations that correspond to our testing. And so with each drilling campaign or not each well, but each drilling campaign, you're going to have increase the number of drillable locations as you drill through your inventory. And you saw some of that in the analyst conference on the horizontals. But since it was kind of -- I hate to say it wasn't in its infancy, but since it was early on operated at the end of last year, you really start to see what this thing will do based on running four rigs up there. And you're probably going to see it with five, too.

Operator

Your next question comes from the line of Anuj Sharma with Pritchard Capital.

Anuj Sharma

My question is regarding your reported rates on the recent Granite Wash well. You reported 14 million a day and 3,000 barrels of condensate and 2,000 barrels of liquids, NGLs. So I believe this is post-processing, so this 14 million a day probably is 1,200 or 1,300 Btu gas. How much of this 14 million a day and 2,000 barrels of NGLs you get at the outlet of the plant?

John Ridens

That's 14 million per day of residue gas. So that's not going to be nearly as high on the Btus, because the NGLs have already been stripped out of it. We get all the residue gas. We get 90% roughly of the NGL component.

H. Clark

That is our recovery.

Anuj Sharma

So your 14 million a day, 1,200 to 1,300 Btu would be 14 million a day, 1,000 Btu residue or there'll be some more volume shrinkage?

John Ridens

Yes, the 14 million a day is the residue gas that's already been shrunk. So the volumes and the Btus have already been stripped, and that's where you get the NGLs. That's how we're paid.

Anuj Sharma

And 2,000 in barrels of NGLs would be 90% of that you're going to get.

H. Clark

I believe that is our recovery.

John Ridens

Right.

H. Clark

That's what we get paid. That's what the outlook -- that's what the plant would pay us. Now that's gross, right. So you got to nip that down to my NRI and my partner. But, yes, we don't get paid in the end that we get paid at the tailgate.

Operator

Your next question comes from the line of Brian Kuzma with Weiss Multi-Strategy.

Brian Kuzma - JP Morgan

I want to make sure I get my facts straight here on this two new Granite Wash wells, did you say which formation is this new interval?

John Ridens

No.

H. Clark

It's in the Granite Wash.

Brian Kuzma - JP Morgan

It's one of the Granite Wash.

H. Clark

Yes, it's one of those seven lobes.

Michael Kennedy

And the Hemphill County, which of these wells was in Hemphill County?

John Ridens

The well that we are currently completing, that we have not released yet, Brian.

H. Clark

Those two are off Wheeler.

Brian Kuzma - JP Morgan

And the Hemphill well, which are those are like five subfields is that in? You guys had like a couple of subfields you kept off Buffalo Wallow?

John Ridens

It's right on the line between the southern fairway and the central area.

Brian Kuzma - JP Morgan

So that would put it like near Buffalo Wallow or -- I guess I'm not sure what that means.

H. Clark

Well, I'm not going spot them for competitive reasons. But needless to say, we've been up north of the line south, in that area, and even further south. But most of the rig activity dates has been designated in the anywhere [ph] from South Buffalo Wallow Camp (sic) [Buffalo Wallow-Camp South] to Frye Ranch. And then Hemphill would be called everything from Buffalo Wallow to Canadian to Mendota. Pick a name, they're irrelevant at this point. But , yes, we've been back and forth across the border but these wells are in Wheeler.

Operator

Your next question comes from the line like David Tameron with Wells Fargo Bank.

David Tameron - Wells Fargo Securities, LLC

Production rate, people are looking at your first quarter production of $419 million and saying if you're getting these big Granite Wash wells, to look at quarter guidance, it implies the quarter would be higher. Can you guys give us any range of where -- what current production is? Or where you think second quarter comes in? Or anything along those lines?

H. Clark

First off, the first quarter reflected the guidance that we put out mainly dominated by the divestitures that happened at the very end of the quarter. Some people pick that up, some people didn't, and so Mike reminded them. But that was the divestitures. And so it was up faster[ph] because I think we guided $411 million or $412 million. And then we sold 3 million, so it was actually fine. But because the rigs rigged up mostly in the first quarter, you saw our spending last year was right on top of our guidance. Even with the acreage overexpenditures like the Eagle Ford, mostly your rig bills, I mean when the rig started spud [indiscernible] and not on New Year's day but pretty close to it. And because of that you get a little bit of lag in the ramp up. The second thing I'll say is, obviously, we've always guided the midpoint. And we've always tried to guess at working interest because we like to drill the highest working interest wells first. But we could grab a farm out or two in places like the Haynesville or Buffalo Wallow, that might be a lower working interest. But we guided the midpoint, we guided the average, and if we continue to exceed expectations, then obviously that would be the next gains, how much better are we doing than that. But we ate the divestitures, which is 5 million a day. So in effect, you've already covered that. And I think in terms of the volatility of the current market, it's probably safe to just leave it where it is. But clearly, Buffalo Wallow becomes a bigger player because of its rates, exceeding the midpoint and because of the additional rig. That has -- and that's a be a growthier area, but we decided to leave it the same and just basically go forward to be comfortable with it. But Buffalo Wallow exceeds our expectations, the other areas were not disappointing yet. It's just that with the liquids and the rates, I don't think we can replicate that elsewhere.

David Tameron - Wells Fargo Securities, LLC

Okay. So no clarity on work term production is or second quarter level?

H. Clark

No. We'll leave it the same and go from there. And like I said, the biggest, I guess the two biggest issues is how these wells perform. And so far so good. And the timing of the Canadian pipeline is their organic growth, because they've already got the wells drilled. And that gives us some surety going forward with the same capital budget that we got, but production was forecasted -- for the guidance to go up throughout the year and average somewhere around, what, $450 million.

John Ridens

$445 million.

H. Clark

So you got to ramp up starting in second quarter, which comes from these areas. They planted these two areas, Canada and comes from the Western Business Unit, Panhandle.

Michael Kennedy

Yes, David, this is Mike. I mean, our guidance was flat for the first quarter, which would have forget $412 million. And then, 10% to 12% organic growth fourth-quarter-over-fourth-quarter, which would put you around for $455 million for the Q4. So you can scope the curve accordingly.

David Tameron - Wells Fargo Securities, LLC

And just to clarify, there were two recent Granite Wash wells that you have 100% interest and 90-plus percent. Those were completed in April, so those didn't show up in first quarter production.

Michael Kennedy

Correct.

Operator

At this time, there are no further question. Presenters, do you have any closing remarks?

Patrick Redmond

Yes, I want to thank you all for participating in our conference call. If you have any further questions, please give us a call. Thank you.

Operator

This concludes today's conference call. You may now disconnect

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Source: Forest Oil Q1 2010 Earnings Call Transcript
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