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Forest Oil (NYSE:FST)

Q1 2011 Earnings Call

May 03, 2011 2:00 pm ET

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

Scott Hanold - RBC Capital Markets, LLC

Brian Singer - Goldman Sachs Group Inc.

Biju Perincheril - Jefferies & Company, Inc.

Andrew O'Connor - Millennium Partners

Gil Yang - BofA Merrill Lynch

Pearce Hammond - Simmons & Company International

Duane Grubert - Susquehanna Financial Group, LLLP

Andrew Coleman - Madison Williams and Company LLC

Unknown Analyst -

Operator

Good afternoon. My name is Kristen, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Forest Oil First Quarter Earnings Conference Call. [Operator Instructions] At this time, I would like to turn the call over to our host, Mr. Patrick Redmond. Please go ahead.

Patrick Redmond

Thank you, and good afternoon. I want to thank you all for participating in our first quarter 2011 earnings conference call. I will note that the replay of this conference call will be available through May 16 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. 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 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 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. Thanks to everyone joining us on a busy earnings day. First quarter 2011 production of 425 million per day was up 6% organically from the same quarter last year. As forecasted, production was affected during the quarter by the repositioning of our drilling program in the Texas Panhandle and down time associated with severe winter weather. Liquids production during the quarter was up 9% organically from last year and comprised 25% of total production. This occurred despite any material production contribution from the Eagle Ford Shale or the Peace River Arch programs, with those wells coming on after March 31. The results from both of these programs are positive and bode well for increased oil production beginning in Q2 and the remainder of 2011.

Differentials were better than expected this quarter for natural gas at $0.38 per Mcfe and for oil at $5.13 per barrel. NGL pricing was positive as well as we realized 44% of NYMEX, and that percentage continues to increase in the second quarter. Production expense for the quarter was $1.34 per Mcfe, up 11% compared to last year. The increased production expense was up mainly due to Canadian foreign exchange and winter weather-related costs and should come down during the remainder of the year.

Cash G&A expense for the quarter was $0.36 per Mcfe and was consistent with last year. DD&A increased during the quarter to $1.76 per Mcfe, as our capital program is almost completely focused on oil and NGL projects, and those projects have higher F&D costs in our current DD&A rates.

Our E&D capital expenditures of $208 million, as expected, was disproportionately weighted towards the first quarter, as our activity in Canada has performed in the winter months before spring break-up occurs. The U.S. business units only spent $130 million on E&D CapEx during the quarter.

We also invested $55 million in acreage in the United States with the addition of 4,000 net acres in our significant Eagle Ford Shale position and 82,000 net acres in new oil-rich opportunities.

Our balance sheet remains strong during the quarter, with net debt at $1.7 billion. Forest borrowing base was reaffirmed in April of 2011 at $1.3 billion, and we have over $150 million of cash on the balance sheet, which results in liquidity of approximately $1.5 billion. We increased our hedge positions during the quarter for both 2011 and 2012. We added to our 2011 gas hedge position and now have 150 million a day hedged at $5.48. This represents a hedge position of 45% of our midpoint gas guidance for the year. We commenced our 2012 gas hedging program by entering into 105 million per day of natural gas hedges at $5.30 per unit. We also entered in the 2,000 barrels per day of NGL hedges for 2012 at approximately $45 per barrel. These are attractive levels for us considering we have realized much lower NYMEX prices over the past year.

So to summarize, Q1 2011 was a bit of a transition quarter, with the redesign of the Texas Panhandle program and commencement of our drilling programs in the Eagle Ford Shale and Peace River Arch. With positive results from the oil drilling, we should see increased oil production in Q2 and throughout 2011.

With that, I'll now turn the call over to Craig.

H. Clark

Okay, thanks, Mike, and thanks for joining us today. We kind of had a lackluster quarter in the first quarter with the weather conditions and other things, both in the U.S. and Canada. February and early March were especially tough. Despite this, we're able to get quite a few positive things done in the quarter, so let's give you the update here. Most notably, we established a proof of concept on our Eagle Ford Shale play with 4 completions averaging about 780 barrels a day equivalents. 730 barrels a day is pure crude oil in those. These all exceeded our medium type curve. We'll be continuing our program here and adding a third lantern rig. As you'll hear from J.C. in a moment, in his operations comment, these oil wells are hanging in there pretty well. We like this play more and more each day.

We added new zones in the Texas Panhandle with Texas 11 million a day with good liquids. In fact, the liquids volumes were 850 barrels a day. It sounds like it's better than the Eagle Ford well. Don't be confused with the average rate in the press release since we're spreading over a much wider geographic area and testing new zones as promised. Even at shallower dips, which come with cheaper well cost in some cases. This is not a depletion phenomenon. With the rig count rising to around 100 rigs in the Panhandle at last check, we seem to hear more and more about new zones, new names and, quite frankly, new areas each quarter.

We also completed a sidetrack of an older-producing vertical well in the oldest field in the Panhandle for us. In fact, I think it's the oldest period, our old Buffalo Wallow Field, which tested 9 million a day equivalents due to small diameter liner. It was a sidetrack. To our knowledge, it's the first intentional sidetrack of this type in the Granite Wash outside casing, which would accomplish significant cost savings from existing vertical wells in the area. It was also in the middle of a densely drilled area, the most densely drilled area or the only densely drilled area for us in the Panhandle. And this well was included in J.C.'s average for the quarter, and it's basically a workover operation. The Evi slate point horizontals in Canada with the new drilling and completion techniques J.C.'s going to talk about turned out well thus far in terms of oil rates and costs. We've just begun to scratch the surface in the area with the use of pad drilling and the optimum lateral rink and associated frac stages. The first Nikanassin area horizontal was drilled and completed in Canada with a short lateral and minimal frac stages. We haven't scratched the surface here either in terms of the number of targets to test horizontally have just begun. The co-mingled vertical wells are not too shabby either in the Nikanassin.

We have a heck of a new ventures initiative to add new acreage in place particularly oiling. We list this acreage so that you'll know where we spent our capital in the first quarter and most of that land was in the new ventures group. No area's off-limits to them. We added approximately 86,000 net acres in the first quarter alone, 82,000 of it's from unspecified new oil plays that new ventures came up with.

In terms of industry conditions we're seeing, it's going to be frustrating the many operatives where they have their economics and hard-earned efficiency gains particularly on the drilling side eaten away by simple price book increases. Other than discount agreements done in early 2011 at Forest, we keep beating back price increases. And as prudent cost-cutters, we had to change the way we approached drilling, completions and lease operating. Most of this will have to involve procedural or mechanical changes currently. This quarter alone, we used the multi-well pads, coiled tubing fracs in Canada, used different prop variations particularly in the Eagle Ford. Reused our water, our frac water in general in both the U.S. and Canada as a few examples. In fact, we've been doing it in Canada for some time.

The swim hole sidetrack in the Granite Wash allowed us to use an existing case vertical well along with this associated existing surface facilities. Our drillers have been affectionately calling this using Tinkertoys to drill the horizontal lateral well. We're also anticipating some cost relief in 2011 particularly in East Texas and also eventually some release on frac cost due to significantly more horsepower coming to market from existing companies and also moving that we would choose to use as well.

In terms of capital spending, we spent roughly $200 million in the first quarter on E&D activity. As in previous years, the higher spending pace reflects the winter activity in Canada followed by relative inactivity in the second quarter in the same Canadian areas. We did see a slightly longer winter season in Canada this year. Winter conditions extended into mid-April. Our CapEx does include some science on our new horizontal targets in the U.S. and Canada and quite an active quarter on land acquisition and we had roughly $55 million in new leases. I think the average cost comes out to be $640 an acre. And it goes up pretty fast if you don't get in early. This includes our new Eagle Ford leases, which is filling in around our existing position, and all these plays have significant oil potential and we entered them all, including the Eagle Ford, at attractive entry cost.

Our production and sales for the quarter were heavily affected by the weather downtime from third-party pipelines also a rig shifting in the Panhandle, the third-party plot Enbridge. We also have lower NGL recoveries in the Panhandle as well that affected us after had their plant farm in Oklahoma, so we lost some of our NGL yield at least for the time being in the first quarter.

We did not see any help in the first quarter from any of our oil wells that J.C.'s going to talk about particularly Evi in the Eagle Ford, as most of these came on late in the quarter or in the case of Evi in April. Our wells in the Panhandle, Eagle Ford and Canada are meeting the median type curve expectations, in fact, the original type curve. I've never had to apologize in my life for making 12 million a day gas wells in the Panhandle before.

On the operating cost side, our per-unit cost basically went up with the lower production. Other than the winter type cost, the lack of production tax incentive refunds in Texas is really the only reason the LOE is up and the overall operating cost. Our absolute overhead cost remained in check for the quarter.

Going forward, our plans for Forest include immediate reallocation of the CapEx to best of economics, that goes without saying, but also to production edge starting with the Eagle Ford program. Clearly, projects in this environment that yield crude or liquids have the best economics and we're running our economics at $5 NYMEX web, $75 WTI and that's not price expectation, that's economics. As predicted, we're already seeing a rebound in the NGL prices we received from exactly a year ago.

We will expand a number of horizontal test on the Panhandle, including those that are much more shallower in the case of oiliness with them. With all the targets in the Panhandle, we've almost got a portfolio within the portfolio, and we're getting off the existing areas as we speak.

With all the targets in the Panhandle, we almost basically have a lot to look at for many years to come and we'll be doing that in the coming months. We'll eventually start back up on East Texas projects when the costs come down, and that of course with liquids means they get a benefit there in places like the Cotton Valley. The 82,000 acres that we leased in the new ventures group are located really on 2 new oil plays, which were about future opportunities for growth for Forest in addition to all the opportunities we've already identified. So we're doing a good job of building the inventory. We certainly have a number of choices for the capital allocation and portfolio. It will always be a portfolio. It won't be 1 or 2 assets, and this goes along with the financial flexibility.

Thanks for listening to the call today. Now I'm going to turn it over to J.C.

John Ridens

Thank you, Craig. During the first quarter, we increased our operated rig count from 6 at the beginning of the quarter to 15 at the end of the quarter. We had 10 rigs running in the U.S., 5 running in Canada, and we drilled 42 gross wells at a 98% success rate. Only 2 of those rigs, the ones drilling in the Nikanassin Resource Play, were dry gas wells, and they have tax and royalty incentives associated with them. The other rigs were all focused on drilling oil wells or liquid-rich gas plays.

In keeping with the same as increasing our focus on oil, I want to begin with our activities in the Eagle Ford oil window. We completed our first operated well in Wilson County for an IP of 800 barrels of oil equivalent per day. The well was recently placed on an artificial lift and the rate increased almost 1,000 barrels of oil equivalent per day with the wells still flowing up to back side. The wells already produced 20,000 barrels of oil since being placed on production in March, and this significant amount of cumulative production is consistent with our first completed well, which has already produced 50,000 barrels of oil in just 133 calendar days for an average of 361 barrels per day. That's calendar days not production days, so it's associated -- it encompasses all the time associated with installation of artificial lift on that well also.

Our second and third operated completions were in Gonzales County and achieved IPs which averaged 740 barrels of oil equivalent per day. These wells are still flowing, and they will be placed on artificial lift when the pressure has declined on them to the point where lift is needed. Our Gonzales activity continues with our fourth operated well that has just completed being frac-ed in 15 stages and will begin flow testing this week. The fifth well will be fracture stimulated in May. The sixth well has reached TD and will also be frac-ed in May, and the seventh and eighth wells are currently drilling. Since beginning our Eagle Ford drilling program, we've increased oil production from 0 to as high as 2,000 barrels per day, which includes the downtime associated with running tubing or installing artificial lift. We expect the gas line to be finished in May to connect one of the wells in Gonzales County, and then we'll begin branching out and tying in the others as well.

Our initial results were above the type curve established, which was based on an IP of approximately 600 barrels of oil per day, barrels of oil not equivalent, with an EUR of about 350,000 barrels of oil. While we're pleased with these results, we still see room for improvement with increased horizontal lengths and increased numbers of frac stages. To that end, we are drilling our first super lateral with a planned length of 7,500 feet that will be completed with 25 frac stages compared to our previous wells that had, on average, lateral lengths of 3,400 feet and 11 frac stages. We've continued to add land in the play, increasing our position by about 4,000 acres during the quarter. Our acreage position now totals 118,400 gross acres and 109,000 net acres. Adding land in production isn't the only adding this going on here, though, as we will be adding a third operated rig from the Lantern Drilling fleet in near future. This is in part due to the oil rates that are being achieved from our new well, but it's also due to the improvement in drill time reserve. Our drilling times have rapidly improved in the play as we continue to hone our technique. The fourth well reached its total measure depth of 12,500 feet in 18 days. Completion cost continue to be a challenge here, but frac crew availability has recently improved, and I think there should be an indication that cost will improve as well.

With positive results achieved so far, we will continue to evaluate the possibility of even further expansion of activity in this play. We should note that our Eagle Ford program has solid economics because it's primarily crude oil, which provides more value than wet gas wells drilled in the trend. Also, the slightly shallower depths allow us to use our medium-sized lantern rigs, which in turn lowers our cost.

Continuing the theme of increasing oil production, our Evi oil program in Canada is progressing. Although we did not get any wells on in the first quarter from our drilling here, due mainly to the utilization of multi-well pad drilling, we completed 11 of the 17 wells drilled in the first quarter. Seven of the 11 wells have achieved an average maximum recorded initial rate of 300 barrels of oil per day, while the remaining 4 wells are cleaning up after fracture stimulation. The 6 uncompleted wells will be completed after spring breakup. And at that same time, we will put 3 rigs back to work in the field and continue that program throughout the remainder of this year. The wells drilled in Evi are all short laterals averaging about 1,800 feet in length and were stimulated on average with 10 frac stages, which is compared to 6 frac stages used in 2010 for that same length lateral. The Canadian business unit was the first company to drill horizontal slate point carbonate wells in this area, which provides valuable data for our continuing drilling program, and I should remind you that the typical Evi well is forecast to cost $2.3 million to drill and complete, and we have 242 future wells identified.

The Nikanassin Play had 4 vertical wells completed that resulted in average initial production rates of 9 million cubic feet per day. In addition, our first horizontal well achieved an initial rate of 6.4 million cubic feet per day. And remember, that's from one zone, even though the lateral was shorter than planned. Production's going to be monitored on this well during breakup to further model the long-term productivity of a horizontal single zone completion versus vertical co-mingled completions so that we can execute on the follow-up wells planned later next year -- this year.

Lastly, the Granite Wash program continues to deliver high liquids rates as well. The most recently completed wells have yielded initial rates of over 1,100 barrels per day. Combined average IP for the 9 wells completed in the first quarter alone was 12 million cubic feet equivalents per day, and 55% of that was in liquids production. Those liquids are comprised of 400 barrels of oil per day and 700 barrels of NGLs per day. And this includes our somewhat doggy sidetrack, as Craig described it, the Buffalo Wallow that came in at 9 million cubic feet equivalent per day. While the IPs achieved are not as high as previous quarters, they still fit in the type curves established for the Southern and Central area that we published last year. The average for the Southern and Central type curves is 10.6 million cubic feet equivalent per day, and our average for the quarter was 12 million cubic feet equivalent per day, so I don't feel too bad about that. We also participated in 6 non-operated wells, 5 of which were in Wheeler County that yielded an average IP of 14 million cubic feet equivalent per day, coming in pretty much in line with our results. We tested 2 new intervals within the Granite Wash during the quarter. Those 2 tests resulted in average IPs of 11 million cubic feet equivalent per day, of which 45% was liquids. These new tests continue to show the depth of the number of intervals that can yield commercial production from the Granite Wash.

The Western Business Unit is now looking at additional intervals both in and out of the Granite Wash to further boost their oil production. While we're still pleased with the results from the Granite Wash, and how could you not be at 1,100 barrels of liquids per day, with the continuing disconnect between oil and natural gas prices, oil rules the day. As a result, the team looks for zones that will result in oil preferentially over some of the higher gas content zones. Our acreage in the Granite Wash is held by production, so we have the flexibility of drilling wells when it makes the greatest economic sense, and we aren't driven by lease expirations here. Since we're in the business of drilling for rates of return and not just for production growth, the oil rates I mentioned earlier for the Eagle Ford should be viewed in terms of value as well as rates. Using $100 per barrel of oil pricing, the value of a well producing 733 barrels of oil per day, which is our average IP, equates to a gas well producing 18.3 million cubic feet per day at $4 gas.

These values demonstrate why we're only running 2 dry gas rigs during the quarter and continue to increase our focus on oil and liquids-rich gas drilling projects.

Operator, we're now ready to take questions.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question is from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

I wanted to follow up on the Granite Wash. Could you just put into context how you're thinking about the number of wells per section based on the recent drilling that you're doing and then the number of zones that are also working that are exposed to the liquid plays that you'd be focusing on here, relative to more of the dry gas zones? Can you kind of big picture put them more into context, and how that's been impacted by your recent drilling, please?

John Ridens

On the recent drilling, Brian, we're still looking at 3 wells per section for most of the field. Although I'll tell you we're going to continue to let the wells dictate how many wells need to be drilled on a section. Let the results dictate that because in some areas, we think it may take more than 3 wells. And that will be determined over longer performance periods. But as it stands right now, we still continue to look at a 3-well per section model in terms of the number of zones that have been tested that had appreciable liquids content. I think we're up to about 6 or 7 now.

Brian Singer - Goldman Sachs Group Inc.

And is there any differentiation in terms of the number of wells per section or within the liquids zones versus the dry gas zones that you're seeing now?

John Ridens

I can't really speak much to the dry gas zones because we haven't done a whole lot of work in that. But I'll tell you in the liquids-rich zones, the only time that we've seen anything that was less than 3 wells per section was as we discussed in the previous quarter in Zone #2. Zone #1 continues to be drilled at 3 wells per section in a large portion of the play. And the other zones as we start testing those and delineating them further, time will tell.

Brian Singer - Goldman Sachs Group Inc.

Great. And you may have mentioned it in your opening comments, in which case apologies for asking, but can you just talk about where your current production is at and particularly on the oil and NGL side or what your exit rate was for the quarter?

Michael Kennedy

Brian, we don't give current spot rates.

Brian Singer - Goldman Sachs Group Inc.

What about the exit rate for the quarter? I just kind of...

Michael Kennedy

We haven't given guidance on a quarterly basis. Our guidance is annual.

Operator

Your next question is from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC

Keeping on the Granite Wash, can you all talk about -- it sounds like you're spraying those rigs around testing a few concepts. I mean, can you help orientate me to sort of expectations over the next couple of quarters of the various areas and intervals that you're testing? Are these -- would that lead you to say that your average productive results, initial production results are going to be a little bit lower than what you've experienced in the past?

John Ridens

No, Scott. I wouldn't necessarily say that because remember when we tested Zone 2, we had higher rates than we had seen in and out of several wells in zone 1. So I think that it's safe to say that as we continue to test and delineate this, there's going to be some pleasant surprises. There's going to be a couple in there that we're going to surprise us to the downside. But what I will say is that if you look at the geographic mix as well as the vertical mix that we're taking in, then certainly, we're going to be looking at increased activity up in Hemphill County because we see a number of targets up there that need testing even more so than some of the stuff that we've dig out down in Wheeler. But we're also seeing some new zones that we want to test that are preferentially on the oil side. And that may yield some pretty good results for us as well. So I think that as we continue to look forward to what comes up in the next quarter, I'll look at what our last quarter results have been, looking at OBO results down in Wheeler compared to ours and we're pretty much running right with the pack.

Scott Hanold - RBC Capital Markets, LLC

Okay, and so as you move up in the Hemphill, correct me if I'm wrong, though, on average, the productivity of those wells are a little bit lower than what you've found in Wheeler County, is that correct?

John Ridens

Yes, that's right, but that's also reflected in our type curves that I spoke of earlier. So when the results are coming in lower in Hemphill, they aren't coming in below expectation. They're coming in as predicted.

H. Clark

There's a few fliers in there, but that's just because it's 3,000 foot shallower.

Scott Hanold - RBC Capital Markets, LLC

Okay, so I mean, I think on average you've in the past, correct me if I'm wrong, talked about sort of an overall Granite Wash type curve of around 15 million a day driven initial production, so do you still see that as sort of a good kind of a bogey in modeling?

John Ridens

That 15 million a day was for the Southern area, and the type curve that was used up in Hemphill was less than that. Blend those 2 together and you get to an arithmetic average of 10.6 million is what I referenced as the average for those 2 areas.

H. Clark

We used 6 million for the Central, 5 million for the North and to the south the 14 million you're referring to, and we've averaged in the teens in the Central, which is the greatest proliferation of wells in this quarter.

Scott Hanold - RBC Capital Markets, LLC

Okay. Thank you for that. And then moving on to Eagle Ford, it sounds like you've made some pretty nice initial wells there. And can you talk what some of the well cost on your average wells were like? You had mentioned 3,400-foot laterals at 11 stages. What was that running? And can you kind of give us an expectation for the super lateral? What do you think that will cost?

John Ridens

Well, our averages so far because of the extra science that we've been doing with pilot holes and cores and enhanced logging programs, the initial wells were about $8 million a piece. And then our super lateral, we're looking at about $12 million. So I think that we're going to get a significant savings because that's going to be the equivalent of almost 2 wells for $12 million. I think also you touched on an interesting point, which is cost trends in this play, and we are working desperately on fracturing services both for our mom-and-pop outfits, as well as looking at different profits to lower that cost.

H. Clark

But those were all had some science, so that cost he quoted including any pilot work we did with the vertical before we sidetracked them at horizontal.

Scott Hanold - RBC Capital Markets, LLC

Okay. Is that super lateral cost to that include some science there? Or is that a good cost to think about in there?

John Ridens

No, there will bit of science in the super lateral as well.

H. Clark

For example, when we logged the lateral itself that was just $1 million of incremental cost on each well. But since they're so far apart, as J.C. described, I think the closest 2 wells are 30 miles apart. We took the data on them because we've got a whole lot of acreage around these particular wells.

Scott Hanold - RBC Capital Markets, LLC

And is your acreage such that they're pretty blocky, you think you could do some like a significant amount of these super laterals if it works?

John Ridens

Yes, absolutely because we've got through the heart of our Gonzales County play, we have acreage that is perfectly suited for pad drilling and extended-reach laterals. So that will be one of the steps for future consideration when we get into so-called full development mode, Scott.

H. Clark

It also holds additional acreage. And in addition to that the acreage that has been purchased late last year and this year, the 4,000 acres, were all essentially filling in the hole in that blocky acreage that we've got in Gonzales County, which is virtually all the land of 100,000 in Gonzales. And we did it for that reason.

Scott Hanold - RBC Capital Markets, LLC

Okay, and so then when these well results come back, I mean from an operationally or from a geological perspective what would be on these extended reach laterals? If this doesn't work, what would be the reason? Is that just because it's more of a pressure thing relative to some other parts of the play?

John Ridens

I think that the only reason that it would not work is that we get on that extended reach so many frac stages that we don't get sufficient drawdown at the toe of the well, and we get dominated by yield performance. But now as it stands right now, we're seeing extended reach laterals longer than this up in the Bakken that are continuing to work, so I think that it should work here too.

H. Clark

We'll primarily dealing with single face flow, no gas, I mean minimal gas and no water, so we can get higher rates up that same size of casing. But clearly, it's a play to try and offset some of the cost that you're seeing in terms of what you get 2 wells for a lot cheaper than you can do or one long well for a lot cheaper than you can do too. But it's basically a way to offset some of these service cost issues. But it would solve holding some acreage, but you hope to make a better well for the cost just then. There's no doubt about that.

Scott Hanold - RBC Capital Markets, LLC

Do you have any kind of like a frac dates up there, given some hard frac dates, firm frac dates to get these wells completed?

John Ridens

Yes, we've got firm frac dates scheduled, and we've been able to get wells frac-ed pretty damn timely. I think about the longest delay that we had, waiting on a frac crew was about 2 weeks, so haven't been too bad.

H. Clark

We did -- it has helped out with increased horsepower coming in from other areas. The availability of frac crews has increased. And also since those are all our own lantern rigs, we're able to move them around at will and hopefully not mix frac dates.

Operator

Your next question is from the line Pearce Hammond with Simmons & Company.

Pearce Hammond - Simmons & Company International

You mentioned on the release on the Eagle Ford that you put one well on pump and indicated others will be put on as needed. What is the criteria? And should we expect production upticks like your first well as some of these subsequent wells are placed on pump?

John Ridens

Yes, the criteria is simply we let the wells flow up casing until the flow rate starts to fall off, Pearce, because as Craig referenced, we've got minimal gas here to help us out with lift. So as we put those on, we do see higher rates initially and those last for a short period there while we're getting more of the water off that has resulted, and it's load water I should say that this resulted in this flow rate dropping off. And then subsequently, our production on the first well, which has been on for about 4 months, has been relatively flat. So we're encouraged by that. So we see initial rates, it's pretty good slowly declines until we put lift on it, goes back up and then comes down to a point at which it pretty much stabilizes.

H. Clark

And these wells, if you talk about uptick, Pearce, they basically, in our mind, are put back on a normal decline or in this case better than a normal decline. Any uptick that you would have over the initial rate is because the wells are, in this case, is a good thing. They're flowing at the backside while we're pumping them up the tubing at the same time, and these are rod pumps. But because we're in the oil window, it don't have a high gas oil ratio where outcomes worked pretty well. In fact, we haven't seen gas interferences issues to date, so it's just the normal course of business. But they're hanging in there.

Pearce Hammond - Simmons & Company International

Great. Thanks for that color. And then switching to the Granite Wash, what are well cost right now, the Granite Wash?

Michael Kennedy

They are running about $7.5 million on average for our operated wells.

H. Clark

And we participated in some to the north with another operator, and that's again in the shallow areas, and I think had been as low as $4 million to $4.5 million, but that's just depth-oriented. And of course, we've seen frac price increases there too. But we've been able to offset that with drilling days.

Pearce Hammond - Simmons & Company International

Great. And then finally, Craig, in the past you've mentioned, you've made the statement that service cost have gone psychedelic. Do you think that we are at that point again? Or are we at a worse point right now? And is there any reason for optimism from your standpoint? You mentioned East Texas is a place where you could see costs come down some. But are you more optimistic or less optimistic on service cost now than when you made that statement?

H. Clark

More optimistic, And the psychedelic was basically confined to I believe the Eagle Ford or the Haynesville 2 years ago, and we're already seeing some of the benefits of that in East Texas.

Operator

Your next question is from Gil Yang with Bank of America.

Gil Yang - BofA Merrill Lynch

So just Craig and J.C., just to confirm, the Eagle Ford wells, that first one, you agreed that the decline is only 50% or so off its peak 24 rate after 4 months. That's performing better than your type curve would suggest in terms of the percent decline, is that correct?

John Ridens

That is correct, Gil.

H. Clark

It broke over sooner.

Gil Yang - BofA Merrill Lynch

Right, okay. In the Eagle Ford, if you go to 3 rigs, how many wells can those 3 rigs drill in the second half of the year in the Eagle Ford?

John Ridens

Well, that's a great question because the way that we're looking at it right now, a lot of it's going to be dependent upon how many of the super laterals do we mix in with that, because those wells will take a little bit longer. But basically, I think that if we put a third rig out there in the summer and continue that 3-rig program for the remainder of the year, we're probably looking at another 15 wells or so.

Gil Yang - BofA Merrill Lynch

And the spend amount would then be about, what about, $90 million something like that? But it can be more than that I guess, right?

H. Clark

Yes, more than that because of the long lateral one.

Gil Yang - BofA Merrill Lynch

Okay, so it's may be $100 million extra.

Michael Kennedy

We'd run our type curve just on the 4,000-foot lateral. It's $6 million to $7 million a well.

Gil Yang - BofA Merrill Lynch

And would that represent an increase in spend overall or a shift in capital spending from other places?

John Ridens

No, that would not be a shift from other places. It would be a reallocation down to the Eagle Ford.

Gil Yang - BofA Merrill Lynch

A reallocation? I'm sorry, say that again, a reallocation into the Eagle Ford from other places?

John Ridens

Yes.

Gil Yang - BofA Merrill Lynch

Okay, and can you comment where you would slow down?

John Ridens

No, we haven't decided that yet, Gil.

Gil Yang - BofA Merrill Lynch

Okay. And going to Evi, could you give your -- you said that the average rate or the peak rate was 300 barrels per day. Could you put that in context of what the average rate was for those wells that you completed and tested and versus the...

H. Clark

That was the average peak rate.

Gil Yang - BofA Merrill Lynch

The 300 was the average peak rate?

H. Clark

The average was of those 7 wells.

Gil Yang - BofA Merrill Lynch

Okay. And what was the number in 2010?

John Ridens

We had a couple, Gil, that were in the 220, 225 range. And our type curve was based on 140 barrel a day average.

H. Clark

And the average in the past was what we would have used in the analyst conference roughly a year ago.

Gil Yang - BofA Merrill Lynch

Right. Great. And then finally, with the Nikanassin well and the lateral length is shorter and you got up fewer frac stages. But that's close enough to be tempting just to say why don't we just multiply everything by 2, and say that if had gotten the full lateral length and the full number of frac stages, actually you would've gotten to 12 million a day well? Is there any objection to that math in particular? But more importantly, if that's the right math, what is the -- given that the vertical well was so successful as it is, what's really opportunity of the horizontal program in the context of the horizontal well versus the vertical well that are about the same in terms of rates?

H. Clark

I think in lieu of the IPO, I don't need to be making any projections. But in the case of the verticals, the decision that will need to be made in the future would be the gas cheaper and more economically by coming on the verticals, which have an average rate that we talked about in the past versus the horizontal, which would cost more, that will be the decision. I don't really need to be speculating and making projections at this time.

Gil Yang - BofA Merrill Lynch

Okay, understood.

Operator

Your next question is from the line of Andrew O'Connor with Harris Investment.

Andrew O'Connor - Millennium Partners

I want to know, can you more exactly say where the new Eagle Ford acres are located, which county? I may have missed that?

H. Clark

That was easy, Gonzales. Right in the big yellow blob in Gonzales. Some of them are contiguous or actually, if you look at it, one of them is actually at the hole of the doughnut. Those are those leases, and they abut us in that county basically.

Andrew O'Connor - Millennium Partners

Okay, and then secondly, can you further characterize the new 82,000 acres? That's a lot of acreage.

John Ridens

It's in the United States.

H. Clark

For the lack of being stealthy, because I don't like to do that, I just want to show what we had gotten for the $55 million that we spent in the quarter in the new ventures group. And it's in the U.S. and it's oily and obviously the price of acreage has gone through the roof already. So but our new ventures group has to be generating new plays. As we go forward, we don't want to run just strictly on any one play and they're going to add some more to the portfolio. But they added a lot of acreage very quick at very affordable prices, and there's still some acreage to be available, so I'll limit the location until then.

Operator

Your next question is from Biju Perincheril with Jefferies & Company.

Biju Perincheril - Jefferies & Company, Inc.

First on the CapEx, clarification. Did you say the Eagle Ford, that would be additive or you're going to be reallocating?

Michael Kennedy

No, it's not additive.

Biju Perincheril - Jefferies & Company, Inc.

It's not additive, okay. And then the new oil plays, is that 2 separate plays, 82,000 acres?

H. Clark

Yes.

Biju Perincheril - Jefferies & Company, Inc.

And what's the timing of testing those. Is that something that will get tested this year or?

H. Clark

Yes, but the first at hand is the core and test, just like we did in Eagle Ford. In both cases, we all or currently has seismic on those prospects. So we'll do some testing this year and that's probably the best time to talk about it, after the fact.

Biju Perincheril - Jefferies & Company, Inc.

Okay. And then in the Eagle Ford, you talked about -- or can you talk about if there are -- what your infrastructure situation is, if there's any sort of delays in ramping up?

H. Clark

No. No delays because with this product being about 95% crude oil, don't have to have a delay to put oil in tank and get it trucked out. When I referenced the gas line coming in, that's just to gather the associated gas that's being produced with this, but it does not preclude us from drilling and completing wells. So we're getting them drilled and completed almost in the same month that they're spud now.

H. Clark

Another gas component and what gas we have, we're using it to run our heater treaters. And our pumping unit engine, they're all gas-fired.

Biju Perincheril - Jefferies & Company, Inc.

Got it, okay. And then as soon as you ramp up the Eagle Ford program, can you talk about what will be your -- if you take a look at your total U.S. volumes, your exit rate would be for oil and maybe if you have it for NGL too?

John Ridens

No. Everything we've been drilling have been focused on has been the liquids and the oil, so we're keeping that guidance.

Biju Perincheril - Jefferies & Company, Inc.

Okay, so I think in your past prior guidance has something like 30% liquid?

John Ridens

That's correct, Biju. Yes, that's correct.

Biju Perincheril - Jefferies & Company, Inc.

Okay, so is that sort of an average for the year or is that...

John Ridens

Annual guidance was 30% liquids.

Biju Perincheril - Jefferies & Company, Inc.

Got it. And then in the Granite Wash area, have you tested the Hogshooter formation?

John Ridens

No, we have not. Hogshooter is an equivalent member to a Cottage Grove zone. We haven't tested that particular one yet.

Biju Perincheril - Jefferies & Company, Inc.

Okay. Is that something that you think is prospective on those side of your acreage?

John Ridens

Yes.

Biju Perincheril - Jefferies & Company, Inc.

Okay.

H. Clark

But the best we can tell is the equivalent. And when I said we'll test some of the shallow zones. We have 2 targeted oil shallow zones in our plan for 2011. It's horizontal and not vertical.

Biju Perincheril - Jefferies & Company, Inc.

So how many zones have you tested altogether so far?

John Ridens

Let's see. I think it's 6 to 8. I don't have that right at my fingertips. But with the addition of the 2 new zones that we just mentioned this quarter, I think that, that brings us up to 8.

H. Clark

Industry talked about 3 new zones, and I'm not counting the Hogshooter. We saw an alphabetical of zone tested. We saw a St. Louis lime or Atoka up in the north, way up in the north by a competitor that's near us. And then we saw another Granite Wash zone, excuse me, an Atoka Wash zone. It's an Atoka zone that traditionally was dry gas and now they've got some liquids in it down south. So those 3 we're not counting because we haven't tested those operated, but those were 3 of the new zones I referred to in my previous comments.

Biju Perincheril - Jefferies & Company, Inc.

Okay. Got it. That's all I had.

Operator

Your next question is from Jeff Robertson with Barclays Capital.

Jeffrey Robertson - Barclays Capital

Craig, just on the acreage, did you say all you will have is seismic on those new prospects?

H. Clark

Currently, yes.

Jeffrey Robertson - Barclays Capital

Okay. And you mentioned in your comments about the Granite Wash a, coming out of a well and drilling a short horizontal that tested at 9 million a day. Can you talk a little bit more about that well in the sense that does that have implications for some of the areas that have been previously developed with more vertical wells in terms of adding opportunities?

H. Clark

Yes, we've been talking about this a long time as a way to not to offset some of the well cost the industry is seeing but as a way to go in and get zones that were previously untested. If you remember Buffalo Wallow was the only field we sort of down spaced. So we wanted a well -- first off, you have to find a well that's not a very good well or depleted. And then, you basically cut a hole in the casing, in this case, 5.5 and drill the 4.5 inch hole inside the small liner. The only thing you gain from that is way cheaper well cost, which loses with the slim hole. You're not going to get some of the higher rates. So what it means for us is more opportunities at a cheaper cost. It also means that some of the depleted fields may not be depleted.

Jeffrey Robertson - Barclays Capital

Will you do any more of those wells as a part of this year's capital program?

H. Clark

Yes, and we've done that with our lantern, I hate to say it, but it's some of our smaller lantern or workover, Essentially, this is a glorified workover.

Jeffrey Robertson - Barclays Capital

And I can't recall, did you say what the cost of this well was?

H. Clark

Gosh, I don't know. It was higher than the vertical but much less than the horizontals. And all we do is cement the casing up, cut a window or a sidetrack and we paid this one because we don't want to twist off in the small hole and the frac actually went pretty well.

Operator

Your next question is from Duane Grubert with Susquehanna.

Duane Grubert - Susquehanna Financial Group, LLLP

Craig, you like to manage by the numbers. And I'm wondering if you could just talk about quantifying the benefit of having your own rig fleet and then maybe also making some qualitative comments about it.

H. Clark

Well quantify, I mean it cost us to run those rigs. So I don't know that the cost savings are in rig rate. I've said this before, I'll say it again. The cost savings of these rigs is we have direct control over the quality of them. So therefore, there's less downtime. I might add we ranked the rigs 2 to 3 years ago when we cut back capital, and they ranked high both in safety performance and also downtime. So I don't think it's in rig rate. It's in performance. And that and, Duane, that's the hands. It's not some special purpose secret sauce. It's the hands. And secondly, savings, and this is a big issue -- I mean when we moved into East Texas, we could move that rig and rig it up in 2 days or one day, and the competitor rigs that we're renting were charging us everyday, 365 years a year and taking 5 to 7 days. Our assumptions of reducing costs in East Texas and eventually the Panhandle and eventually the Eagle Ford was because if you spot us those 4 or 5 or 6 or 7 days upfront that you're paying full rig rate for under a term contract, you can never catch up with us. The last but not the least, the benefit is we move them around at will, reallocate capital or not, and it helps us when we have a lease expiring or getting a lease or getting a farm out, move the rig over there. You're 2 weeks away from just about any rig you want.

John Ridens

To that end, another point that Craig touched on was the downtime. We're running a couple of rigs down in South Texas that have had a lot of downtime associated with repairs. But fortunately, we've not seen it with the lantern rigs. And even though after you hit a repair clause in that contract you're not paying day rates anymore, you're still paying for all these associated rentals and everything associated with that. So there's a savings there as well.

H. Clark

The term contracts that they give they charge it 365 days out a year, and you have no control over the quality of rig if you have a term contract.

Duane Grubert - Susquehanna Financial Group, LLLP

That's helpful. Another question about a metric, with the market being very intent on you guys getting oilier period-over-period, do you have a specific gas versus oil venture that you guys are managing too internally?

H. Clark

Well I know you'd like us to be that way too. But no, as you know, I like to make money wherever we can. If the well cost got much cheaper, gas would be a benefit. Unfortunately, that has not happened yet. But that, if you remember it was cost that moved our Haynesville rigs on East Texas, not the price of natural gas for a Haynesville well.

Biju Perincheril - Jefferies & Company, Inc.

And certainly not the performance of the Haynesville well.

H. Clark

Yes, but that was a -- and J.C. did add right there too. But we made a cost call, and it was a pretty good one. But clearly, liquids are a superior price unless the well cost are that big of disconnect. And until gas comes down, the liquids drilling is going to be favorable, whether it has gas or NGLs with it or not. It's just that the cost have not come down to meet what I guess the commodity price is. The one thing I will mention is I don't think people have picked up on is a lot easier and simpler to frac a type gas like the Granite Wash than it is a Eagle Ford well. And the reason is the number of frac stages and the amount of fluid you use. So I used the word frac intensity. Those wells are less stages, less frac for pretty good results with the same or better results. And therefore, you're less sensitive to service cost on that type of well or Cotton Valley well than you are on an Eagle Ford well that might have 20 fracs on it or a Bakken well that might have 40 fracs on it.

Duane Grubert - Susquehanna Financial Group, LLLP

Okay, and then finally, with your new acreage potentially setting up a couple of new areas or segments, with the Canadian spend, and I realize you're not going to comment on that directly, do you intend to create any technology transfer by maybe reassigning Canadian focused geo-personnel to your new play? Or how should we think about -- how are you going to staff up your new stuff in light of you're already running at a pretty hefty rate?

H. Clark

I can't -- the lawyers won't let me speculate on technology transfer anything I can say that in Canada's existing staff which will stay with -- there are unconventional people there as there are in the U.S. So each entity will have similar staffing and similar staffing needs.

Operator

Your next question is from Cathy Milostan with Morningstar.

Catharina Milostan

Thanks for taking the call. I just have 2 follow-up questions related to some of the discussions I've heard earlier today. One was to talk about how because of your high oil content in Eagle Ford Shale, there's probably a high probability that you'll probably looking to more artificial lift. And I was just trying to get some color onto what potentially could be the cost related if you were to go down the path where you're going to use a high percentage of wells and use artificial lift for those, how does it affect the cost of the wells, and also what steps you need to take to make sure you get that step, that stage put in place with your drilling program?

H. Clark

That one's pretty easy because we do it all the time elsewhere, just like we did in the Permian Basin. It's a pumping unit. So we'd make the surface facility slightly higher. But remember, there's slightly shallower wells so it more than offsets the cost of the artificial lift equipments only a couple of hundred thousand dollars.

Catharina Milostan

Great. So it would be fairly easy to get that set up for an ongoing program with all your wells?

H. Clark

We're using the oldest form of artificial lift known to mankind, rod pumping, the horse's heads. So, so far so good in terms of getting that type of equivalent, which is basically a pumping unit rods.

Catharina Milostan

That's terrific. And then also, since we're all looking at those new venture acres that you've lined up, and just -- obviously, we're very early in the stage of that. But any sense of how you're going to be allocating some of your staffing and technical expertise to handle these new acres in the new venture play?

H. Clark

Yes, we've got a new ventures group that reports to me. We staffed that up late last year and early this year just for this reason. That's the same group that found things like the Eagle Ford in Québec, the Utica, and that group is centralized but works all the regions, and then they'll have that for both Canada and the U.S. currently.

Catharina Milostan

And when you're set to transition those net acres into the exploration development stage, do you envision you'll have enough staff to take care of that?

H. Clark

Yes, we basically -- they're all, I hate to say the word scientist, but they're mostly geo-scientists and reservoir engineers on land. When we go to operations and put wells on and operating cost and marketing, we transfer that to their respective business units. So those individuals are actually located in those business units in Denver.

Operator

Your next question is from Eliezer Felicia [ph] with Maxim Group.

Unknown Analyst -

Just 2 quick questions. First one is back in Nikanassin. The 4,000-foot lateral at the 12 frac stage, is that your target goal on that area, or should we expect a different number? And I have a follow-up on that.

John Ridens

I think that, that still remains what our target is. And the first well we pulled the trigger on a little prematurely, so that we could ensure that we got it completed before breakup hit because we didn't want to have 3 months go by with no test results. And then going forward, I don't see any reason to change that model today as we get more production out of this shorter horizontal that will help guide us towards the right answer as well.

Unknown Analyst -

Got you. And then second one will be on your -- in your release, you announced that there were total cash costs related to a certain extent to what are disposal and some compression costs. Is that expected to be recurring, or it's just one-off because of weather?

John Ridens

Most of that will be reoccurring. But hopefully, it will be spread out along larger volumes so that per-unit number should come back down.

Unknown Analyst -

Great. And then just one final question. Just in general, how many of your quarterly operated rigs are in all your zones? Do you have any of those rigs also in Canada, or are those meant to be third-party owned?

H. Clark

No, all the Canada rigs are third-party owned. The U.S. are the only plays we own the rigs. And pretty much all the rigs that are running right now are the ones we own.

Operator

Your next question is from Brett Hall with Global Hunter Securities.

Unknown Analyst -

Do you have any plans to sidetrack laterals in the Granite Wash?

H. Clark

I'm sorry could you repeat that, Brett, I couldn't hear you?

Unknown Analyst -

Do you have any plans currently to sidetrack laterals in the really Granite Wash?

H. Clark

Yes, we tried the sidetracks, but that's been one of our ideas all along, and another operator has tried one of those. There will be, in our case, not opposing laterals where they're going different directions. They'll be dual stack. We had thought that might make sense for co-mingling 2 of the lesser zones, but we just haven't gotten there yet because of singles that worked that well so far.

Operator

Your next question comes from Andrew Coleman with Madison Williams.

Andrew Coleman - Madison Williams and Company LLC

I had a question on I guess as you look at ramping up operations there in the Eagle Ford and as well as adding the rigs per unit in the Granite Wash, what are the delays, I guess, between when you move the rig off to get in the frac unit in there and from you when you get the frac for crude done when you tie it in? Are those nominal? Are those still a few days?

John Ridens

It's still a few days, but I would term it as nominal simply from a standpoint that I think about the best turnaround that we've had from rig release to get in the frac crew in there and get it started has probably been about 8 to 10 days, the longest has been a little over 2 weeks. Once we get down to the point of artificial lift needs, that goes very quickly. That's usually a 2- or 3-day install from the time that we rig up to kill the well to the time that it is pumping.

H. Clark

And we frac them in both the U.S. and Canada, oil or gas. We basically put the frac right up against the pipeline so that we're cleaning the well up in the sales.

Andrew Coleman - Madison Williams and Company LLC

Okay, all right. And then thinking about -- you made a comment earlier and I couldn't -- I didn't hear which area it was referring to, but the well decline here was breaking over a bit sooner. Was that the Eagle Ford or was that the Granite Wash?

H. Clark

He was asking what the outperformance was for the first Eagle Ford well and that's because it broke over quicker on this hyperbolic decline.

Andrew Coleman - Madison Williams and Company LLC

What B factor would you say that would equate to? Are you -- would you propose using that for the rest of the wells that you drill or you do think it was a one-off?

H. Clark

We're sticking -- I'm not of a B factor guy. I'm a recovery factor guy. So I can tell you that. But in the case of the decline curve, it's ought to get back to what B factor, but we're still using the same decline curve. The IP, I think, J.C. said was just short of 600 barrels per day, and that gives you somewhere around 350 Mboe, but it's -- all the wells are IP and are above the curve at this time before we drill.

Andrew Coleman - Madison Williams and Company LLC

Okay, sounds good.

Operator

At this time, I would like to turn the call back over to Mr. Redmond for any closing remarks.

Patrick Redmond

Thank you. This concludes our conference call. I want to thank everyone for their interest and participation in our call. If you have any further questions, please feel free to contact us. Thank you.

Operator

Thank you. That does conclude today's conference call. You may now disconnect.

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