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Executives

Patrick Redmond - Vice President of Corporate Planning and Investor Relations

John Ridens - Chief Operating Officer and Executive Vice President

Michael Kennedy - Chief Financial Officer and Executive Vice President

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

Analysts

Jeffrey Robertson - Barclays Capital

Brian Singer - Goldman Sachs Group Inc.

Scott Hanold - RBC Capital Markets, LLC

Dan McSpirit - BMO Capital Markets U.S.

Biju Perincheril - Jefferies & Company, Inc.

William Lee - Scotia Capital Inc.

David Tameron - Wells Fargo Securities, LLC

Gil Yang - BofA Merrill Lynch

Alex Meier - Zimmer Lucas

Scott Wilmoth - Simmons

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Richard Johnson

Forest Oil (FST) Q4 2010 Earnings Call February 22, 2011 2:00 PM ET

Operator

Good afternoon. My name is Christie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Forest Oil Fourth Quarter and Year End Earnings Conference Call. [Operator Instructions] I will now turn the conference over to Mr. Patrick Redmond, Vice President, Corporate Planning and Investor Relations.

Patrick Redmond

Thank you, and good afternoon. I want to thank you for participating in our fourth quarter and year-end 2010 earnings conference call. I will note that the replay of this conference call will be available through March 8 as described in our press release issued this morning. We have, joining us today, Craig Clark, President and CEO; Michael Kennedy, Executive 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. Reconciliations 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 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, forecast, 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 to everyone joining us on a busy earnings day. Fourth quarter 2010 production of 472 million per day was up 3% sequentially from the third quarter and was within guidance. This was achieved while generating free cash flow during the quarter of $40 million. Also, fourth quarter 2010 production was up 19% compared to the same period in 2009 pro forma for divestitures. Notably, the 19% organic growth was mainly attributable to liquids production as we were able to increase liquids for the period by approximately 50% or over 6,500 barrels per day. The 6,500 barrels per day growth in liquids production was about the size of our Permian Basin divestiture in December of 2009.

So we've essentially grown our liquids production back to levels that existed prior to the divestiture, while not levering the balance sheet and have put $800 million of divestiture proceeds in our pocket. These results highlight the quality of our asset base and our ability to allocate capital to liquids-rich projects. Differentials were better than expected this quarter for natural gas at $0.41 per Mcfe and oil at $6.59 per barrel. NGL pricing was positive as well as we realized 45% of NYMEX, and this trend has continued in 2011.

Production expense for the quarter was impressive once again as our relentless cost-cutting initiative drove it down to $1.06 per Mcfe or 4% from the same period in 2009. Cash G&A expense also decreased to $0.29 per Mcfe from $0.42 per Mcfe from last year. Total cash cost for the quarter came in at $2.16 per M compared to $2.44 last year representing a 10% plus reduction. As we like to say, this is a margin business, and the ability to possibly effect and control the cost line item in a rising service cost environment sets Forest apart from its peers.

DD&A increased during the quarter to $1.66 per Mcfe from $1.55 last year. The increase was a result of higher future development costs due to the elevated service cost environment and from our drill bit F&D costs of $1.90 per Mcfe.

Our E&D capital expenditures decreased in the quarter to $118 million from $149 million in Q3, driven by a slowdown in drilling activity as we repositioned our rig fleet for deployment in 2011. For the year, we had E&D capital expenditures of $656 million, which was below guidance of $675 million to $700 million. The ability to control capital has become a calling card for Forest and demonstrates our commitment to efficiently spend capital despite rising service cost.

During the quarter, Forest's net debt remained flat at approximately $1.7 billion despite free cash flow of $40 million during the quarter. This was due to our investment in working capital as the majority of our interest on our senior notes is paid in December. Liquidity remains at $1.5 billion as we have an undrawn $1.3 billion borrowing base and over $200 million of cash on the balance sheet.

Hedging. We increased our 2011 natural gas program to approximately $140 million a day hedged at swaps of $5.54. This completed our 2011 hedging program that resulted in our typical percentage of production hedged at 40% to 50%. We also completed our liquids hedging program with 4,000 barrels of oil hedged at a collar of approximately $78 by $89 and hedged 5,000 barrels of NGLs per day at approximately $38. In total, we have natural gas equivalents of about $200 million a day hedged at $6.70, which will nicely underpin our cash flow for 2011. We started our 2012 hedge program with $20 million a day hedged at $5.40 per Mcfe and 2,000 barrels per day of NGL hedges at $45 per barrel. We anticipate a normal hedging program for 2012 and targeting 40% to 50% of production hedged, so you'll see us adding to our hedge portfolio over the coming months.

We have updated our guidance to reflect the weather and infrastructure downtime in Q1 2011 and recent results in the Texas Panhandle Granite Wash. Production guidance for the year was decreased to 470 million per day from 490 million per day. The majority of the reduction will take place in Q1 as we've seen severe downtime from the recent cold weather. Production in Q1 is forecast to be negatively affected by approximately 4 Bcfe. However, our guidance still represents 5% organic growth, while our capital expenditures of $600 million to $650 million will be at or near cash flow.

So to summarize the quarter, Forest was able to achieve 3% organic growth while generating free cash flow. To have organic growth while not levering the balance sheet puts Forest in an enviable position, and we expect these trends to continue into 2011. With that, I will now turn it over to Craig.

H. Clark

Thanks for the summary, Mike, especially with all the moving parts at the end of the year. We had a very active and successful 2010 and fourth quarter in the year. I'll go over 2010 results first, address 2011 and followed by our outlook for industry trends.

During 2010, as most people know, industry was faced with headwinds in regards to gas prices and particularly substantially increased onshore competition with service cost rising more than anyone predicted alongside the availability of these services themselves. Our biggest accomplishment in 2010 may have been that we replaced and even had higher absolute fourth quarter production than a year earlier after selling around $1 billion of properties in late 2009.

As Mike mentioned, we did this while keeping net debt essentially flat. Certainly for 2010, we saw solid performance in terms of organic growth in both production and reserves. We did this while increasing production guidance throughout the year and maintaining the same capital spending discipline. We're also able to add quite a bit of undeveloped land, approximately 120,000 gross acres or approximately 90,000 net solely in our core areas without breaking the bank or creating burdens on lease expirations. We've done a good job of managing spending obligations while adding to the portfolio.

Our flexibility and optionality is excellent. Let's start with the metric for me that most folks focus on in year-end reserve replacement, our total company proved reserve grew 9% pro forma for the divestitures and for 2010 to a total of 2.24 Tcfe using 12-month prices of $4.38 per NYMEX natural gas and $79.81 per crude. We had extensions and discoveries of 384 Bcfe for 213% reserve replacement and all-sources F&D of $2.18 per Mcfe. Our drill bit reserve replacement was 209% at an F&D cost of $1.90 per Mcfe. Liquids as a percent of our mix grew as well. The 39 Bcfe of negative revisions were minimal and came mainly from increased future development cost as we reflected the current service cost environment.

This was also a factor in our DD&A rate. We had virtually no revisions from PUD locations dropping out to the SEC five-year rule as our PUD percentages remained about the same. It increased slightly to 3% at year end due to a single horizontal PUD being better than the associated vertical location the year before. The only horizontals booked of any kind in Canada are at the Evi oilfield, and we have yet to book any horizontals in the Nikanassin Play or other zones outside the first two Granite Wash, Atoka or more on the Panhandle and of course in the Eagle Ford. So we remain conservative with D&M doing about 87% of our company's reserves.

We divested approximately 62 Bcf of non-core and mainly non-operated properties in Canada and U.S. during 2010 for total proceeds of $167 million. Most of the reserves sold were proved developed with limited upside. I should mention a few more items regarding our all-sources F&D cost. First, we included all CapEx in our calculation, which included our land acquisitions of approximately $109 million. Also included would be any coring, testing, in other words, science for the new plays like the Eagle Ford or the Deep Basin horizontals. It also includes the cost associated with moving our drilling rigs around.

Service cost continued to influence industry F&D, although we were able to offset some of these with efficiency gains in the Panhandle and Deep Basin. We've noticed industry fining costs trending upward a little bit due to liquids drilling activity and our liquids contribution contributed somewhat to our F&D as well. However, the shift we made in the second quarter of 2010 away from gas areas, in particular, areas with higher regional inflation was at the right time in the cycles, specifically East Texas, North Louisiana.

As we mentioned earlier, our E&D CapEx spending was in line with guidance despite external cost pressures, no pun intended on the word pressure as in pressure pumping. Our total E&D spending for 2010 was $656 million with an additional $109 million spent on acquiring new undeveloped land. Forest drilled 148 gross wells with 93% success rate. Most were operated by Forest, and about 2/3 of these were horizontal. We did a commendable job as we did in years before holding our lands with vertical production, while managing lease expirations so they don't manage us.

Entering 2010, we had projected that frac cost, proppant, tubulars and directional services would increase overall well costs by 5% to 10%. This obviously came to bear out sponsored by frac cost for us in industry, but we may have seen 15% to 20% instead of the 5% to 10% we saw in 2010. We were able to offset this with some efficiency gains, but not all of it.

Our fourth quarter E&D spending was only $118 million and actually was 20% lower than the previous quarter and essentially flat with a year ago. As Mike mentioned, with our CapEx spending levels, we generated free cash flow even with the winter drilling season starting in Canada. Unfortunately, that made for a slower start in 2011.

Our operated rig count in the fourth quarter averaged seven rigs, five in the Panhandle and two in Canada along with a few non-operated wells in the Panhandle and one in South Texas. All were drilling horizontals except one rig in Canada. Our current rig count is 13 rigs operated: six in the Panhandle; two in the Eagle Ford; two in Canada's Nikanassin Play, and one of which is horizontal; and three in Canada's Evi, Red Earth light oil area.

On the production side, as Mike mentioned, our net production was up 3% sequentially within the guidance range even with the lower spending pace. We were able to offset any material winter weather-related downtime for the most part in the fourth quarter. Canada pipeline was weather-challenged but was up and down in the month of December, but did come on around the 1st of December. Our fourth quarter production grew organically during 2000 (sic) [2010] to the extent, as I said earlier, that we completely replaced the billion dollars of properties sold at the end of 2009.

Clearly, 2010 wells throughout the portfolio exceeded our risk projections while liquids grew proportionately in production much more than gas. In terms of lease operating expenses and expense G&A, we had another strong quarter and year, with most of our areas reporting lower premium cost. This is certainly contrary to industry trends. It's the fifth year in a row Forest has been able to extract more margin through controlling expenses.

Our commodity prices were up slightly in the fourth quarter, specifically NGLs, prices were up, sponsored by a rebound in ethane prices. This is a good lead into our plans for 2011. We're currently using NYMEX pricing, and $5 for gas and $75 for WTI crude with approximately 40% of the crude price used for the NGL blend. So no change on gas, but we raised our crude and NGL forecast. No surprise that liquids projects will fare better than dry gas even with disproportionate cost inflation related for crude over gas projects.

Brent to WTI crude premium is now at an all-time high of $16, not too sure all of it's justified. However, the good news for Forest is that we have about 3,000 barrels a day of Louisiana light and Canada light that gives the Brent type premium to WTI. NGL prices have run up lately with the cold weather and also because of the plant explosion at Mont Belvieu, Texas.

Our CapEx levels of 2011 are near expected cash flow. We originally guided E&D CapEx to be 5% below last year with production growth to start out the same at about 10%. Our lower guidance that we included in today's release was a function of two things: A higher perm in one of our Granite Wash zones and the large weather downtime that occurred since early February. J.C. will go into our current assumptions for the effected Panhandle zone. Certainly, we are draining a larger area than we first thought, thusly less CapEx to recover the reserves in the small area.

We have seen a huge ramp-up in activity in the Granite Wash with all the great results for us and competitors. We've got a lot of company out there now. The weather downtime came from downstream pipes and plants that froze up with the all-time record temperature subzero, in fact, in the Panhandle that we saw in northern Texas and Oklahoma as well. In fact, our largest purchaser Enbridge, had over 500 million a day down, we're told, in the Anadarko area alone, with numerous downstream compressors offline at that point that backed up the gas. Canada did have an outage but strictly routed to a force majeure declaration by TransCanada. These outages affected industry supply. But also, we decided to get out in front of our guidance with our future plans and this downtime.

We can get the downtime back, but our future exploration plans in the southern area will involve less wells per section in the small area that we've identified, and we will also be testing new zones. The average rate will be less impactful in other areas but still have a rate of return. In fact, as we have in our recent investor presentation, even the Granite Wash wells we drilled in the third quarter have already paid out.

We recently participated in two new horizontal zones tested from 12 million to 20 million equivalents a day, so we're off to a good start with identifying two new zones. The wildcard in our 2011 guidance is the contribution from the Eagle Ford, the new Granite Wash zones, the Nikanassin horizontal since no material impact was included for those. Our first Eagle Ford well, when we had 50% working interest, exceeded our expectations, with our 600 barrel a day IP mid-case. So far so good.

So we are proceeding with our 100% working interest program in the oil window. It doesn't hurt that the offset competitor wells support these results. In terms of industry environment, trends we're seeing only a few years back, the average well consisted of 60% drilling cost and 40% completion. Currently, it's the other way around.

In May, we even get the 70% completion cost, which tells you where we and the industry need to focus going forward. Forest has been successful in the past because we focused on the big components first, which previously was rig cost, and our rig ownership did wonders.

Now the single biggest component, at least in these horizontal wells, is the frac stimulation cost. During 2011, we think the availability issue will be alleviated by new horsepower and new entrants, but we won't get much price relief until 2012. The exception being East Texas, North Louisiana where we should see some deflation but not the hotspot for regional inflation, which will be the Eagle Ford or the Bakken. I should note that Canada did not see this type of price and service volatility in 2010. Forest will consider changing our completion designs, including in the Panhandle and other areas, which I've sidetracked dual horizontals, packer or poor technology or simul-fracs where we can do our fracs in batches any way we can to reduce the cost of the frac job and might make our production as more blocky, but it could save us some completion dollars over the long haul. We just can't stand still with these cost increases.

We may get some cost relief as I've said earlier and may move back into East Texas, North Louisiana later of the year as activity comes down there. Remember, it was not the gas price that drove us out of there, but the cost in the first place. I expect to see quite a bit of valiant activity with gas as the bargain in crude being high-priced. The competition for resource plays has become intense. We saw a high-priced transaction today, so we may have a higher chance of developing these organically, including new zones over the same acreage like the Panhandle. We hope to make core area acquisitions in 2011, but these may be hard to come by because of secret zone in these high areas like the Panhandle.

That wraps up my overview, and I'll turn the call over to J.C. for details on the operations.

John Ridens

Thanks, Craig. Let's get to it straightaway this afternoon, addressing the recent developments and the actions that were taken in the Panhandle. In early February of this year, in the second zone that we tested in the Granite Wash sequence, we found depletion on the last well drilled. The average 24-hour IP of the previous wells drilled in this zone was 25 million cubic feet equivalents per day, and our latest well drilled into the same reservoir quality yielded a 24-hour IP of only 9 million cubic feet per day.

While disappointing compared to the previous wells, we can't complain too much about a well with an IP of 9 million cubic feet per day. Further, since drilling our first wells in this area in March of 2010, through year end, we have produced 9.7 Bcfe, 61% of which was liquids from five wells, which have an average production time of 133 days, and were still producing 18 million cubic feet equivalent per day at year end.

We will not be drilling three wells per section in this area as originally forecasted. We're dropping the down-the-middle locations. This encompasses 2,500 net acres of our total acreage in the Panhandle, and this will eliminate the remaining five planned drilling locations in this area in 2011.

Instead, we will be moving the rig program for those wells to Canadian Southeast and also to test other zones. Speaking of Canadian Southeast, we completed three additional wells in this area, achieving an average 24-hour IP of 13 million cubic feet equivalent per day, of which 39% was liquids. Our first four wells in Canadian Southeast have averaged 9.5 million cubic feet equivalent per day for their first 30 days of production. This performance exceeds our type curve, which is based on a 30-day IP of 7 million cubic feet equivalent per day.

Our first well has a cumulative recovery of approximately 8/10 of a Bcf equivalent in its first five months of production or 41% of the wells that we replaced in the southern area over the same timeframe. Wells of this type will yield a rate of return of about 40%, which is consistent with our current price forecast.

Through not only our operated program but through non-operated wells, we continue to see new zones tested in the Granite Wash sequence. We've participated in two non-operated wells, successfully testing two new intervals, which tested 12 million and 20 million cubic feet equivalents per day, respectively. These data points serve to further develop our inventory in the stacked pays of the Granite Wash as we see 18 potential locations developed from these two successful tests, one of which we are currently drilling into in an operated well.

We plan to run a six-rig program in the Panhandle this year. We continue to evolve not only our stimulation designs, but our casing designs in efforts to reduce costs on development. Notably, we are sidetracking an existing vertical well horizontally to determine the feasibility of this technique in boosting reserve recovery.

On the stimulation front, we continue to tweak our frac designs to lower the cost in an attempt to abate some of the cost increases seen from service providers and yet still maintain high initial rates and ultimate recoveries. Our high initial rates have been proven over time. Our cumulative recovery on our 2010 wells have averaged 3.5, 3.1 and 1.5 Bcf equivalents, respectively, for wells that were drilled in the first, second and third quarters of 2010. From a cumulative revenue standpoint, they have generated $19.5 million, $14.3 million and $7.8 million, respectively.

With our wells running just over $7 million on average, we are reaching payout very quickly on the Granite Wash and still showing good production levels thereafter, even though we have already recovered approximately half of our projected reserves for wells that were drilled in the first quarter.

We're encouraged by the early results of the Eagle Ford Shale program, and the first well drilled in Wilson County achieved a peak rate of over 800 barrels of oil per day and is still flowing over 600 barrels of oil per day after 40 days on production. We're running economics based on an IP of approximately 600 barrels of oil per day with 350,000 barrels of oil ultimate recovery, so this well has exceeded our type curve so far. A well of this type will yield a high rate of return, approximately 80% of development cost, once all the initial science types of wells have been drilled.

This well was drilled with a 5,300-foot lateral and frac-ed with 11 stages. Our first operated well, also in Wilson County, is currently completing. We're pleased with our drilling results and that this well reached TD in 30 days compared to the non-operated well, which took 72 days. These both included drilling vertical pilot holes, so we expect our drilling times to decrease once we're in development mode.

We have two operated rigs in the Gonzales County portion of the play now with numerous permits in hand. We have seen high rate wells drilled around us with Magnum Hunter and EOG both reporting IPs exceeding 1,000 barrels of oil per day. Further boosting our oil production, we have resumed horizontal drilling in the Evi oilfield in Canada.

We have three rigs running in display with completions of the initial wells beginning now. Drilling an Evi well only takes about 10 days, so a three-rig program can add significant production in this field. In the Nikanassin, drilling results continue to be positive with our latest two vertical wells having average IPs, 24-hour IP of 12 million cubic feet per day. We have two rigs in the field currently, with one rig almost to TD on our first horizontal well, and the second rig continuing to drill vertical wells. We are on pace to get the horizontal well completed prior to breakup so that production could be monitored with the goal of shifting more of the drilling in this area from vertical to horizontal wells.

Our infrastructure project was completed in late November, so we don't anticipate further pipeline expansions this year. Drilling results continue to improve in the Nikanassin with our last three vertical wells taking an average of 37 days from spud to rig release. The first vertical wells took about 70 days on average, so we've seen yet another significant improvement.

Operator, we are now ready to take questions.

Question-and-Answer Session

Operator

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

Scott Hanold - RBC Capital Markets, LLC

When looking at sort of the Granite Wash and you have locations that you're now expecting down-spacing more so. That's a total of five locations as far as entire acreage position that really impacted that. Is that what you think right now? And could this high permeability aspect be relevant to other parts of your acreage position as well?

John Ridens

Scott, it's J.C. All we're seeing right now is this one area affected, and that's where we have drilled our most prolific wells. It's also where we ramped up the activity in the highest percent, so it's the only one I can speak to right now.

Scott Hanold - RBC Capital Markets, LLC

Is there like any indications from the area that you did see this that it could be applicable elsewhere? Or is that something you just need to put more holes in the ground?

John Ridens

We'll have to have more holes in the ground, Scott. We found higher permeability here as evidenced by some booming well results and when we got into the last well and found the depletion that told us that this well is communicating with others, and it's simply because we've got higher permeability.

Scott Hanold - RBC Capital Markets, LLC

And then in terms of like your production guidance you obviously had to reduce it. So how much of that was just weather-related versus I guess moving from this area in the Granite Wash to less productive areas?

John Ridens

Well, the production impact of our guidance is about five Bcf for just these five wells because as I pointed out, our initial wells in here, we were getting almost two Bcf in five months, and I think Canadian Southeast, we're getting 8\10 of a Bcf in five months, so roughly a B per well for each of the five wells.

H. Clark

The remainder would be weather\the top line downstream stuff.

Scott Hanold - RBC Capital Markets, LLC

And with regards to the weather stuff, is that all taken care of? I mean, are you guys fully back-up production on that stuff, and what are you currently producing right now?

Michael Kennedy

We don't give spot daily rates but J.C. can. . .

John Ridens

Yes, we're not fully back up yet, Scott, because some of the downtime that we've incurred results in higher line pressure, which knocks out some of the more mature production, which takes a while to get back on.

H. Clark

And a little bit of it, Scott, was in Canada, but that was TransCanada force majeure in the middle of their startup and bringing the new wells, but most of it was in the Mid-Continent area.

Scott Hanold - RBC Capital Markets, LLC

On the Eagle Ford, I think your budget implies something like two rigs working for the first half of the year, and it sounds like you've seen good offset well results as well as the non-operating results. I mean, how much more capital could you deploy there? And obviously you've got a lot of liquidity with $200 million of cash in the bank. Are you still looking at a JV? Or would you think about a JV opportunity on that acreage? Or do you have plenty of liquidity to go at it yourself?

H. Clark

Well, this is Craig. We have plenty of firepower to go for ourselves, but we have guided the company, including Canada, as if everything stays the same, and then post-Canada, we'll have to have some decisions in terms of whether we fund that. But clearly, the success would mandate some more funding. And a JV's an option, but we're prepared to go it at this time. A two-rig program I think would give you more than $50 million for the year. I know it would, so we've got permits actually longer than that, but the first two wells are 50%. Those were just sharing, and we get everything including coring and then from this point forward, unless it’s in the remote area, we'll go straight to the drill bit that J.C. alluded to. And so far so good is the short answer.

Operator

Your next question comes from the line of Brian Lively of Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Just thinking about the Granite Wash and the rest of Wheeler County outside those 2,500 of high perm rock. What are your plans to develop Wheeler County? I see you're adding over to Hemphill, but where does Wheeler County stack up?

John Ridens

We continue to run rigs in Wheeler County, testing intervals that we had tested previously, expanding on that, as well as testing new intervals, Brian. So we have activity continuing in Wheeler County, and we have activity continuing in the same area that we had completion just in different zones. So given the multi-stacked pay nature of this, we continue to operate both in Wheeler and in Hemphill. But if you'll recall from the analyst presentation, we've got a large block of acreage in Hemphill that we had targeted getting very active in, so we just increased that activity somewhat.

H. Clark

The only restriction we've made is in part of Wheeler on the 2,500-acre that J.C. referred to.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

And outside of that acreage, have you guys actually tested wells at 160-acre spacing?

John Ridens

Yes, we have. We have drilled three wells per section in a couple of sections. And I think that what we have found out of that is that there needs to be three wells per section over some of this acreage. You can't drain it all with two wells per section because that perm that we spoke to so far has been limited to a small area.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

And with that, do you think that there's a chance that you could have had a higher perm streak that was pretty isolated on that one well, on the 2,500-acre block? I mean, how reflective is that one well of the overall acreage?

John Ridens

Well, given that this well was drilled in an undrilled section, I think that it's pretty indicative that we've got higher perm that's pretty extensive or we wouldn't have seen the well result that we saw, Brian.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

And last question for me is what type curve then would you say on average you're using for your 2011 production guidance in the Granite Wash?

Michael Kennedy

We're using the type curve that's out there for the analyst day for the Hemphill, and then Wheeler, we're using more of a type curve that's reflective of 2010 results.

Operator

Your next question comes from the line of David Tameron of Wells Fargo.

David Tameron - Wells Fargo Securities, LLC

Why move the rig up north to Hemphill? Why not leave it in Wheeler and drill from those locations given the better rates of return there?

John Ridens

Well, for one thing, we had locations all ready to go in Hemphill, and so it allowed us, once we'd found this depletion just a couple of weeks ago, to react quickly and move that rig up to where we could already maintain activity, David.

Michael Kennedy

And keep our frac dates.

David Tameron - Wells Fargo Securities, LLC

And then go on, if we think out six months or a year, infrastructure issues, where might there be bottlenecks? Or how are you guys positioned as far as 2011 in bringing those wells online?

John Ridens

So far, I think that we're positioned pretty well. We've been working with our service providers out there with our drill schedules, including our revised drill schedule, and new infrastructure is being added to accommodate those volumes. So currently, I don't see anything that should be a major holdup provided that all the infrastructure gets completed on the timeframe that they've indicated, which is short term, should be two to three months to get major projects up and running.

David Tameron - Wells Fargo Securities, LLC

You guys briefly touched on this, but is Eagle Ford and Nikanassin, are those results embedded in 2011 production guidance? Or are they not included? Or can you just remind us what's in there and what's not?

Michael Kennedy

The Nikanassin, we've got the results embedded in 2011 guidance with the horizontal well being a potential flyer if we get good results out of that because we did put a risked rate into that. Other than that, we were running the remainder of the Nikanassin at our type curve type of economics, which we've seen borne out over time. In the Eagle Ford, we've put a limited number of wells in, reflecting the economics that I discussed previously with IPs of about 600 barrels of oil per day.

David Tameron - Wells Fargo Securities, LLC

And assuming a two-rig program?

H. Clark

At just a $50 million, not anymore.

Michael Kennedy

Eight wells.

David Tameron - Wells Fargo Securities, LLC

Last question, and I don't know if this goes to Craig however, but the Eagle Ford, there's noise out there about a potential Eagle Ford JV or that there's acreage being looked out. Can you just talk about, Craig, what you're thinking along those lines? And how you think about that process?

H. Clark

Well, there's been a lot of JV activity in our area with two transactions I guess late last year in both the oil and the condensate window up in what I'm saying our area up north as opposed to down south, there in the Maverick Basin. And because of that, we, from time to time, give reverse inquiries because of the oiliness and also because of the JVs and also because the price of oil has run since then. We don't need a partner, but if it's attractive, we'll consider it.

David Tameron - Wells Fargo Securities, LLC

Do you have a data room open then? Or is this just more of. . .

H. Clark

No, I can't speak to data rooms except we don't have a classic data room. We just ask a banker to field any reverse inquiries.

Operator

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

Brian Singer - Goldman Sachs Group Inc.

You mentioned earlier you continue to believe in three wells per section in some areas. Can you quantify what percent of your Granite Wash acreage in Wheeler and what percent in Hemphill you have seen results that suggest three wells per section?

John Ridens

Brian, I can't really tell you an exact percentage. I can only recall about two sections that we've downspaced to three wells per section so far because most of our drilling has been going toward drilling initial wells per section and testing different zones. So we haven't really gone to a full development scenario in a large area. So I can't really speak to that. All of our activity up in Canadian Southeast has been limited to about one well per section so far.

Brian Singer - Goldman Sachs Group Inc.

So is it safe to then say that three wells per section is still what you expect but a lot more work then has to go into delineating that, that it will actually pan out beyond the 2,500 acres and beyond the couple of sections that you've been successful?

John Ridens

Yes, I think that, that's exactly right because as we talked about last year and we continued to point out, our geographic expanses as play continues to expand. We've got 30 miles apart between horizontal wells going from north to south, and we continue to expand that. So our activity has never been, with the exception of this one area, focused on drilling a whole bunch of wells. We only did that in this one area because the wells were so darn good.

Brian Singer - Goldman Sachs Group Inc.

And within the 2,500 acres, are there any implications for other zones in terms of also two wells per section or still to be determined?

John Ridens

Still to be determined because within this area, to date, all five wells have been drilled into the same interval view. We have not tested other horizons that I can speak to today.

Brian Singer - Goldman Sachs Group Inc.

And shifting to the Nikanassin, can you just give us an update on the backlog there and the timing of bringing that backlog on the production?

H. Clark

We don't have backlog up there, Brian.

Brian Singer - Goldman Sachs Group Inc.

Everything's all back on?

H. Clark

The only thing that other than this pipeline startup that's on with the TransCanada cut us back at one of the gas plants this winter, but nothing shutting the way on pipeline unless we're waiting on a completion, and we'll have to get all those wells completed and on if we get them on this season by March 31.

Brian Singer - Goldman Sachs Group Inc.

And then lastly, you mentioned that you would consider doing acquisitions in your core area, but there's also been this discussion about whether you would joint venture a portion of the Eagle Ford. Can you just talk to as you look out for doing acquisitions if not to Canada, and if not Eagle Ford, would that just be focused on the Granite Wash? Or do you see something getting into new areas?

H. Clark

You never rule out new areas because you obviously like to have some, but I think we do those organically. When I say the core, that would be our three main areas, which would be the Mid-Continent, which includes the Panhandle, East, the Ark-La-Tex don't forget about that, although we saw one transaction in that area today, and then other plays. I guess the reason you're not singling out Eagle Ford is because the price of poker for a buyer has been pretty high, so you're looking at doing that organically and just adding to your core areas, including buying your partners out. So it would be in the three main core areas, including Canada, although we're limited on what we can say about Canada until the IPO.

Operator

Your next question comes from the line of Gil Yang of Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

Just to refresh my memory. As I recall, the 2,500-acre region that you're talking about was not one of the original areas that you had counted in inventory when you had your analyst meeting a year ago. Is that right?

John Ridens

That's correct, Gil.

Gil Yang - BofA Merrill Lynch

And in terms of the spacing issue again, are you going back to rethinking spacing at all around the rest of the Wheeler County acreage? Or that's not really an issue yet?

John Ridens

No, it's not an issue yet because as I said, this is the area that we found significantly higher permeability. And with the work that we have done in the rest of Wheeler County, we have not encountered that phenomena.

Gil Yang - BofA Merrill Lynch

In the Eagle Ford, could you comment on how much of your acreage -- you made the comment in the Gonzales, you've had successful wells drilled all around you. Could you comment on between the Wilson County and the Gonzales County acreage, what portion of your acreage has been de-risked by offsetting wells?

John Ridens

Well, I can't tell you an exact percentage, but I'll tell you that we've been basically boxed in on the north, south -- I mean on the east, south and west portions of Gonzales with higher rate wells. And then down in Wilson, we've seen obviously our own activity and some activity to the west and south, which indicates good results. Now I'm not going to extrapolate that and tell you that it has de-risked all of our acreage, but I'll tell you it sure makes it looked like it's in a good ZIP code so far.

H. Clark

Most of the data points that J.C. referred to from offset wells were in Gonzales County. The reason we did the 50-50 deal in Wilson if you've seen our map, it's not that big. It's a pretty good chunk of acreage, but it's not the big block in Gonzales where most of our drilling going forward will occur. Fortunately for us, that's where most the good data points have come from EOG and Magnum.

Gil Yang - BofA Merrill Lynch

If you looked at EOG's analyst meeting presentation from last year, I think in June when they rolled out their Eagle Ford acreage, they showed an Isopach Map of the area, and it suggested that any of the acreage to the west of where their acreage had been was in significantly thinner zones -- had significantly thinner zones of Eagle Ford pay. Would you say that the results that you've seen between your results and from the offset operators would suggest that, that's irrelevant or the math was wrong?

John Ridens

Well, I would suggest that not everybody calls the Eagle Ford top and bottom in a consistent fashion. And so when we would look at it, our top is somewhat lower than what EOG has called it in the past. And so as a result, I think that we've got a thickness convention issue right off the bat. But based on the results that we're seeing out of the first well in Wilson County, which would have been drilled into what EOG would have called a thin area, well, it's performing pretty darn good.

H. Clark

And we're to the east and north of them. We're not to the west of them.

Gil Yang - BofA Merrill Lynch

And last question is for the Nik. Will you announce the horizontal well before the end of the first quarter or before that we report the first quarter results?

John Ridens

We haven't determined that yet.

H. Clark

The Canadian IPO will move a week in the normal course of business is all we can talk about for Canada right now.

Operator

Your next question comes from the line of William Lee of Scotia Capital.

William Lee - Scotia Capital Inc.

Just had a quick question just regarding I guess, your IPO. Do you guys have a timeframe for that?

Michael Kennedy

William, this is Mike. We can't discuss anything about the IPO.

William Lee - Scotia Capital Inc.

And then just getting back to -- I guess just to clarify. The drainage issue is just constrained to 2,500 acres. Is that correct?

H. Clark

Yes, it is.

Operator

Your next question comes from the line of Jeff Robertson of Barclays Capital.

Jeffrey Robertson - Barclays Capital

A question for you on the Granite Wash. The 2,500 acres you said this was an undrilled section. So does that mean you all did not have any vertical well control in here to help you with these different zones? And then to follow that, in the other areas that you have in Hemphill County, do you have good vertical well control to help give some understanding of what the permeabilities might be in these zones?

John Ridens

Yes, but I'll tell you something, Jeff, and you raised a very good point. Our vertical well control indicated no issues with seeing some of the perms that we have seen in the one area because had we seen this kind of permeability, we would have never had the need to go to 20-acre downspacing for Granite Wash. We would have been able to drain a whole lot more reserves. Our vertical well control tells us that there are a number of intervals that are completed in each of these wells. We do not, from that vertical well control, however, have the ability to predict which can be a higher perm well necessarily because when we run the spinner logs, we see disparate production profiles and that may be limited to a very near wellbore condition, which will not translate into a horizontal performance. In the one well that we've talked about, we had vertical well controls, did not indicate that we were going to have a significant depletion issue. However, with the offset horizontals, we obviously are contacting better overall permeability resulting in a depletion scenario.

Jeffrey Robertson - Barclays Capital

So it could be just a streak of high perm rock in there that you couldn't predict from what you knew?

John Ridens

Could be, but we're seeing a pretty broad area affected. Usually, I think about a high perm streak as having a very partial depletion, and in this case, we saw significant depletion.

H. Clark

Jeff, we did have vertical well control in most areas before we go horizontal, and it could indicate that maybe one zone was being drained better than anybody thought vertically, which would lead to believe the other zones have more potential than them. But clearly, we had some vertical control and based all our horizontal work to date on the vertical testing, which clearly has not been consistent with the horizontal, but it might explain the higher rates on the horizontal.

Jeffrey Robertson - Barclays Capital

So will you all go back I guess and look -- is it too early to have really tried to understand where this is coming from and how it could apply to the rest of the position up here?

Michael Kennedy

Well, I think that what it means for this 2,500 acre is that we don't see the need to drill those down the middle locations at this point in time. Obviously, we'll continue to monitor this, and if we see production leveling out in a fashion that's different than what we're currently predicting, we may revisit that issue. But right now, we're saying we don't see the need to drill anymore, so we'll limit it to two wells per section and save that capital to go employ into areas that we don't see this phenomenon.

Operator

Your next question comes from the line of Scott Wilmoth of Simmons & Company.

Scott Wilmoth - Simmons

Just wondering on your Eagle Ford program you guys have eight horizontals wells planned. Do you guys have any plan for Lee County?

John Ridens

No horizontals in Lee County. We've been drilling some vertical wells in Lee but at this point, we don't see anything except horizontal activity in Wilson and primarily in Gonzales.

Scott Wilmoth - Simmons

And have you guys seen any good results out of your horizontal chalk up in Lee County?

John Ridens

We've had some tweaner [sp], but nothing that I would stand up, pound the table about so far.

Scott Wilmoth - Simmons

Not sure if you can answer this or not, but on the Canadian light oil play, what did you guys book those horizontal wells at, at year end?

Michael Kennedy

I think we have -- our latest information if that EURs on our analyst day presentation. It's in our analyst day presentation, it's 135,000 barrels.

H. Clark

That's based on the program that we drilled in the first quarter of last year, and that turned out well for us.

Scott Wilmoth - Simmons

And then when I think about the horizontal Nik, based on assumed cost, what kind of IPs or EUR uplift you guys need to make horizontal development worth there?

John Ridens

Well, I would say that our general rule of thumb we have not fine-tuned this thing down to the final numbers, but our rule of thumb is we usually look for a two to threefold increase, and we're using about a seven and seven model out there, so the short answer would be we'd be looking for something that's three times that.

Michael Kennedy

And that 7x7 is actually a lot of vertical zone, so this would just be a specific horizontal zone.

John Ridens

So maybe something in the neighborhood of 10 million a day IP with a somewhat flatter decline than what we've seen out of the verticals.

Operator

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

Dan McSpirit - BMO Capital Markets U.S.

On the Eagle Ford Shale, your first non-operated well was first produced on a restricted choke size of what 18/64s. For how long was that well producing at 18/64s? And does the restricted choke size help explain why the well has yet to be put on artificial lift?

John Ridens

Yes, it does explain that. I think, Dan, because it was produced on that 18/64s probably for about 25 to 30 days, if memory serves. And I think that’s what that points to is our intent is to have a higher IP and have artificial lift rate for installation immediately so that we can just continue on and as higher rates in the area as possible.

Dan McSpirit - BMO Capital Markets U.S.

And then how early in the life of the well do you anticipate putting the well on artificial lift then?

John Ridens

It'll depend entirely upon how the well performs but all I'll say is that we will be ready with artificial lift as soon as the well is completed. We'll just be in a standby mode basically for that pump.

H. Clark

Dan, this is Craig. And this was not -- we did not operate but this was not an attempt to do restricted rate like they're doing in the other shales or in the gasy part. They just chose to restrict the well because of tight capacity, and that's just what they did. But it certainly met our expectations and was very stable. I don't think there were any artificial lift savings or anything like that. It was tight capacity and tank truck limited, even though I think that the situation could be resolved.

Dan McSpirit - BMO Capital Markets U.S.

And then lastly, here you state in the press release that based upon further success that you would consider expanding the Eagle Ford Shale program in 2011 this year, what specific signs of success are you looking for either on operated wells or those drilled by others?

John Ridens

I would say that what we're looking for is are the wells going to match our type curve IPs? And are we going to see sustained production as we have seen on this first well? We start seeing sustained and increasing IPs, then I think that the answer is yes, we're going to keep this program going.

H. Clark

And then we'll work on the cost after that.

Operator

Our next question comes from the line of Alex Meier of Zimmer Lucas.

Alex Meier - Zimmer Lucas

One of the things I was wondering about is when you guided to your locations in your March analyst day in the Panhandle, what kind of spacing were you assuming?

John Ridens

We were assuming basically about 210 acres per horizontal well, which equates to three wells per section.

H. Clark

Only on the sections that had, had horizontal as of that date.

Alex Meier - Zimmer Lucas

And obviously not including that 2,500 acres where you're testing the new zone.

John Ridens

That 2,500 acres at the time that we guided in our analyst day, we didn't even have that because it hadn't been tested yet. That was found subsequent to the analyst day.

H. Clark

And nor did we have the other zone, but we were very clear that if we had a vertical at the analyst conference, that section was counted as a vertical and not a horizontal, and the evolution goes we're testing more zones. So that information is dated but certainly that was the criteria at that time.

Alex Meier - Zimmer Lucas

How do you think the number of horizontal locations you have now would evolve assuming kind of what you've learned from the additional zones you've tested?

John Ridens

I'd tell you that that's a moving toward target because we continue to be surprised to the upside with the number of zones that we've found that can be produced horizontally up here and yield significant results. So as we keep peeling this onion, it keeps getting bigger.

Alex Meier - Zimmer Lucas

And then lastly, what kind of EURs are you assuming in your 2011 guidance for Wheeler County?

John Ridens

We're using the results that we got off of the 2010 program. I can't tell you the exact number. Up in Hemphill, we're using about 5.4 Bcf per horizontal well.

Operator

Your next question comes from the line of Rick Johnson of Tygh Capital.

Richard Johnson

Was there an opportunity to complete the well you drilled in the depleted zone in a different zone? And if so, why didn't you?

H. Clark

No, there was not that opportunity because when we drill a horizontal, especially in the upper members of the Granite Wash, there is nothing behind the pipe for us to complete. It's a one trick pony, and so we drilled this well for one specific target. The lateral was all within that one target. There were no other completion opportunities. And at the time, we had no idea that we were going to face this when we drilled it. It was only after the completion came in that we knew it.

Richard Johnson

Are there any other prospective zones in that same location that you could drill a different well to that look good on the logs?

John Ridens

There may be. I can't tell you specifically yes or no. Deeper targets, there may very well be, but I just simply don't have that information at my fingertips.

H. Clark

In that part, we've announced that we've tested two zones in the Granite Wash series in Atoka, and there are actually seven Granite Wash, so we've tested two of five. And us in industry will continue to test these there and other places, but just two of the Granite Wash section is all we've done horizontally in the zone.

Operator

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

Biju Perincheril - Jefferies & Company, Inc.

Can you say how much was booked out of the Granite Wash last year?

John Ridens

I'm not sure I understand your question, Biju.

Biju Perincheril - Jefferies & Company, Inc.

Total reserves booked in 2010 from the Granite Wash.

John Ridens

We don't break that out, Biju. We just do it by country.

Biju Perincheril - Jefferies & Company, Inc.

And then if I look at the new production guidance, are you still expecting some sequential growth, quarter-over-quarter growth starting in the second quarter? And any guidance on 4Q-to-4Q growth?

Michael Kennedy

No. I mean, you can do some math, straight line math, but we don't give guidance on a quarterly basis.

H. Clark

We are expecting sequential throughout the year, just like this because of the capital program.

Operator

Your next question comes from the line of Gil Yang of Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

Just a quick follow-up question on Granite Wash. You said that -- I think, J.C., you said that the Wheeler County wells give you 2 Bcf in the first five months; and in Canadian Southeast, you get about 0.8. Is that what you said?

John Ridens

Yes, for that, and I was referencing once again that 2,500-acre area, Gil.

Gil Yang - BofA Merrill Lynch

So why would if Wheeler County not 2,500-acre well give you in the first five months?

John Ridens

I can't tell you that number just off the top of my head. I'll have to get back to you on that one, Gil. The results vary obviously from area to area, but I can take that with you off-line.

Operator

There are no further questions at this time. I will now turn the conference back over to Mike Kennedy for closing remarks.

Michael Kennedy

Thanks for joining us today. This concludes our conference call. If you have any further questions, please feel free to contact us. Thanks, again.

Operator

Thank you again for participating in today's conference call. You may now disconnect.

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