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Continental Resources, Inc. (NYSE:CLR)

Q1 FY08 Earnings Call

May 5, 2008, 10:00 AM ET

Executives

Warren Henry - VP of IR

Harold G. Hamm - Chairman and CEO

Jeffrey B. Hume - Sr. VP of Operations

Jack H. Stark - Sr. VP of Exploration

John D. Hart - VP, CFO and Treasurer

Mark E. Monroe - President and COO

Analysts

Subash Chandra - Jefferies & Company

Monroe Helm - CM Energy Partners

Thomas E. Covington - Broadpoint Capital

Eric Hagen - Merrill Lynch

John Freeman - Raymond James

Joseph Allman - JPMorgan

Operator

Good day, ladies and gentlemen, and welcome for the first quarter 2008 Continental Resources earnings conference call. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. [Operator Instructions]

This conference call includes forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the company's control. Other than historical facts or company statements included in this conference call, regarding the company's strategy, future operations, drilling plans, estimated reserves, future production, estimated capital expenditures, projected costs and potential of drilling prospects and other plans and objectives of management are forward-looking information.

Forward-looking statements speak only as of today's date. Although the company believes that the plans, intentions and expectations reflected here in or suggested by forward-looking statements are reasonable. There is no assurance that these plans, intentions or expectations will be achieved.

Actual results may differ materially from those anticipated due to many factors, including changes in oil and natural gas prices, industry conditions, drilling results, uncertainties in estimating reserves, uncertainties in estimating future production from enhanced recovery operations, availability of drilling rigs and other services, availability of oil and natural gas transportation capacity, availability of capital resources and other factors. For a more complete statement of risks, please see the company's reports that have been filed or may be filed with the Securities and Exchange Commission.

With that, I would now like to turn the presentation over to Mr. Warren Henry, Vice President of Investor Relations. Please proceed, sir.

Warren Henry - Vice President of Investor Relations

Good morning, everyone, and welcome to our first quarter 2008 earnings conference call.

The format this morning will be as follows. Chairman and CEO, Harold Hamm, will provide a brief overview of our company's first quarter achievements, our strategic positioning in key resource plays and our opportunities for growth in the second half and beyond. Following Harold, Jeff Hume, Senior Vice President, Operations; and Jack Stark, Senior Vice President, Exploration, will provide greater detail on recent developments in their areas of responsibility, focusing on each of our key operating regions. At that point, we will be ready for Q&A.

Also available at that time to answer your questions will be Mark Monroe, President and COO; and John Hart, VP and Chief Financial Officer. With that, I would like to turn the call over to Harold.

Harold G. Hamm - Chairman and Chief Executive Officer

Good morning and thanks for joining us on the call. This morning, Continental Resources announced record financial results for the first quarter of 2008. We have great deal of important information to share with you today. So, I won't repeat many of the numbers in the press release, but I would like to highlight a few and the most significant of those.

We posted record oil and gas sales of $225 million for the first quarter of 2008, an increase of 94% over the $116 million reported in the first quarter last year. Total revenue was $228 million for the most recent quarter. Net income was $88 million for the first quarter, an increase of 164% over net income of $33 million for the first quarter 2007. Last year's first quarter net income is on a pro forma basis as if we had been a tax paying subchapter C corporation in the first three months of 2007.

Given our current environment of strong crude oil prices and the April 30th exploration of our crude oil hedge, we expect these excellent first quarter financial results to continue to improve during the balance of the year. Reflecting this outlook, our Board recently approved increasing the company's capital budget to bring it more in line with our stronger cash flows and to take advantage of the company's significant inventory of drilling and leasing opportunities.

We have increased our 2008 CapEx budget for drilling, land and seismic by $167 million, which is 27% higher than the budget approved last November. $65 million of this increase is allocated to the Bakken play in Montana and North Dakota where we have a dominant operating position. An additional $39 million is allocated for new land acquisition. This represents the doubling of our land CapEx budget to $78 million.

I know our strategic position of Bakken is important in itself, but it also fairly illustrates our broader strategic approach to U.S. resources plays. I believe that these resource plays today offer a tremendous opportunity, perhaps even historic opportunity to exploration and production companies that have the expertise and capacity to exploit them.

To be one of the winners, Continental almost established a strong position in resource plays with the most potential. This requires that we be ready to find each opportunity, establish a viable acreage position and exploit technologically, these plays, which is always challenging. Once we have unlocked the code, exploiting a resource play becomes a process of manufacturing, production reserves, duplicating our successes efficiently.

Finally, even as we are successful in one area, we must be engaged and prepared to take new positions of significance in other resource plays as a potential in mergers. This is what Continental has accomplished in the Bakken and the Woodford, and is committed to achieve elsewhere in the United States. We are prepared to talk today about a play in Western Oklahoma and Texas Panhandle, some of you have called our stealth play.

Jack Stark will address this significant play in further detail today. One last observation before turning call over to Jeff Hume, you will note from our press releases that we are ramping up drilling activity through the balance of this year. We began 2008 with 13 operated drilling rigs. We now have 22, and we expect to reach 30 by yearend. As a result of this increased activity, we expect our 2008 production exit rate will be about 43,000 barrels of oil equivalent per day, or about 42% higher than average rate for the first quarter just ended.

There is a tremendous amount of momentum going into 2009. At this time, we are not increasing our previous 2008 production guidance of 12 million to 12.9 million barrels of oil equivalent, due to fact that our accelerate drilling program is mainly back-end loaded in the year. Obviously, we will update you further if that outlook changes.

With that, I'll turn the call over to Jeff Hume, our Senior VP of Operations. Jeff?

Jeffrey B. Hume - Senior Vice President of Operations

Thank you, Harold. In the Red River units we continue to operate four rigs drilling infield wells. Oil production was inline with our budget model, which include a conversion of nine wells from production to injection representing about 620 net barrels per day.

As reported in February the gas plant was down for equipment repair for about one and one-half months, which resulted in the net loss of 4 million cubic feet per day for the quarter. Plant conversions producing wells to water injection will continue throughout 2008 with increased in production rate resulting from response to injection beginning in the second half of 2008 and continuing through the first half of 2009.

Our engineers continue to refine operation performance and now see an opportunity to accelerate production volumes by expanding water injection and production capacity in the Cedar Hills Units. The capital budget increase includes 17 million to implement this increase in injection rate and resulting production. The expected result would be 2000 barrels of oil equivalent per day increase in the 2009 peak to 21,000 barrels of oil equivalent per day. This operation should add reserve due to enhanced sweep efficiency, we are not modeling a reserve gain in the economics this time. The accelerate production has a 150 million in PV-10 value net of capital investment.

Just east of our Red River units is our Haley Red River project, where we hold 70,000 net acres leasehold and 100 square miles 3D seismic. This area is an extension of Arizona Red River B Play with secondary recovery potential. Last year we completed four wells with an average of 150 Mboe primary EOR. We have recently finished drilling in Merle Johnson [ph] well and shipping in completion operation later this month. We plan to drill eight wells in 2008 and 100 additional square miles 3D seismic.

Now I'll turn over to Jack Stark, who will update you on the Williston Bakken.

Jack H. Stark - Senior Vice President of Exploration

Thanks, Jeff. As most of you have probably aware of the USGS recently announced that the Williston basin Bakken is the largest continuous oil accumulation they have ever assessed with up to 4.3 billion barrels of recoverable oil and 3 TCF of associated gas. It was 25 times more than what originally recognized by the USGS 13 year ago, which is the direct result of the advancements made in technology during this time and that it is likely the amount of recoverable oil from the Bakken will continue to increase the drilling and completion technologies, its prove in the coming years.

Continental recognizes potential early in the development of play and began leasing back in 2002. As a result Continental is the largest producer and controls the largest acreage position in the Williston Bakken play today, with approximately 487,000 net acres under lease. And we continue to build our position with 66,000 of acres added so far this year.

Continental is also one of the most active operators participating in one-third of the 74 Bakken wells currently drilling in the play. As Harold noted the company is increases 2008 drilling CapEx for the Bakken play from 36%, as it increases 36% from a $180 million to $245, million which will increase the number of expected completion from 20 to 28 net for the year.

This budget increase includes cost for the additional completed wells and reflects cost associated with the added wells in progress at yearend due to the increase rig count. The company is currently operating 10 rigs in the play, four in Montana, six in North Dakota.

We will be increasing that count to 12 in May and 13 during the third quarter with the additional rigs being deployed in North Dakota. There are also three additional rigs operated by ConocoPhillips that are drilling on the company's behalf within the 50-50 area of mutual interest in North Dakota.

Drilling results had been inline with our expected average recovery of 300 Mboe gross from our 320 acre infilled and 640 tri-lateral drilling in Montana as well as our 1,280-acre drilling along with Nesson Anticline in North Dakota.

During the quarter, we completed 18 gross, 8.1 net wells. And as detailed in the press release, you can see some of our more recent completions with 7-day initial production rate ranging from 348 to 609 barrels of oil equivalent per day. The average 7-day initial production rate for all wells completed so far this year has been 340 barrels equivalent per day.

We also had a very significant completion here recently, and Jeff will provide you some details.

Jeffrey B. Hume - Senior Vice President of Operations

Thank you, Jack. Our Rocket [ph] prospect or Pleaton [ph] 118 had a peak IP of 1077 barrel oil equivalent per day and a 7-day IP of 760 barrels oil equivalent per day. The Pleaton well is the first well in our Rocket prospect where Continental has implemented a mechanically-diverted completion technique.

That technique will employ uncemented liners and open-hole packers in a single lateral on 1280-acre spacing. This configuration allows us to individually stimulate up to 10 separate intervals utilizing plug and perforations between stages.

As we have mentioned previously that this completion technique has improved results in Norse area. In addition to the McGinnity 1-15H, which we discussed last quarter, the Nelson 1-131H was completed this quarter for 404 barrels oil equivalent per day, a 7-day average IP. Now, we have strong evidence that this technique improves results our southern acreage as well.

I'll turn it back to Jack who will give more information on the Bakken.

Jack H. Stark - Senior Vice President of Exploration

Also significance to our Bakken play, we finished drilling our first Three Forks-Sanish test at the Bice 1-29H in the Rocket prospect and our interest is completing the well this week. We do not have any production rate to share at this time, but we were very encouraged by the shows in the shortest time but were encouraged by the shows while we drilled the well.

The Bice well is equipped like the Pleaton with an uncemented liner and swell packers. It will be completed in 10 separate stages using the plug and perf method Jeff just described.

For those of you listening who might not be familiar with this formation, the Three Forks-Sanish lies immediately below the lower Bakken Shale. All of our previous wells have been drilled within the middle Bakken zone, which lies just beneath the upper Bakken Shale.

What we are testing with the Bice is a theory that the Three Forks-Sanish zone is not being drained by wells drilled in the middle Bakken and therefore may add significant reserve potential to our acreage in the overall Bakken play in the Williston. We'll need to watch production for a period of time, of course, to assess the results, but should have some initial results to share in the coming months.

Elsewhere in the Rockies, I thought I'd also mention that we'll begin drilling on our East Lustre project later this month. This will be the first of three wells scheduled for the year on this project, which is located in Roosevelt County, Montana. The primary objective of our drilling in the East Lustre project is a logical reformation.

Late last year, we acquired 42 square miles of proprietary 3D seismic data across the 28,000 net acres and have unidentified 25 locations for the logical and other locations or other objectives in there.

Those of you familiar with the North Dakota Dickinson Lodgepole reef discoveries in the early to mid-90s know that these are high-risks, but very high-reward opportunities. Hopefully, we'll have some good results to share with you next time.

With that, I'll turn it back to Jeff who will you an update on our Arkoma Woodford project.

Jeffrey B. Hume - Senior Vice President of Operations

Thanks, Jack. In Arkoma Woodford, Continental recently completed its first four wells simul-frac with excellent results. Four wells had a combined initial flow rate of 17.3 million cubic feet per day with individual flow rates ranging from a low of 3.8 million per day to a high of 4.9 million cubic feet per day.

7-day IP average for the four simul-frac wells was 40% higher than the average 7-day IP average for the first two wells in the spacing units, which is very encouraging results for this technique. The four wells were drilled parallel to each other within a 640-acre area with approximately 1,320 feet interwell spacing. The lateral was ranged and linked between 3,500 and 4,500 feet and had between five and seven separate frac stages each. We plan to cut out a two-well simul-frac later this quarter.

The company has begun to see measurable operational efficiencies in the Oklahoma Woodford play also. Drilling days have been reduced 23%, which allows more wells to be drilled per year without increasing the rig count. Accordingly, the company has increased its 2008 drilling CapEx for the Arkoma Woodford play from $100 million to $127 million and expects to complete an additional 3.4 net wells in the Oklahoma Woodford play by yearend.

During the quarter, the company completed 6.1 net horizontal Woodford wells and began acquisition of 18 square miles proprietary 3D seismic in our Salt Creek project, which should be completed in June.

In other Mid-Continent activity, in Blaine County, we had significant completion on our Marriott 1-18, which completed flowing 2.6 million cubic feet per day from the Springer, and as of this morning, was up to 2.75 million cubic feet per day. We recently set pipe on another Springer well in Blaine County, the Wolsey 2-9, which we'll begin testing soon. The company plans to keep one rig drilling in Blaine County area throughout the year, targeting both Morrow and Springer sands.

And I'll turn it back to Jack who'll cover the Michigan area.

Jack H. Stark - Senior Vice President of Exploration

Thanks, Jeff. In the Eastern Division, our three-operated Trenton/Black River completed wells continue to produce at state-restricted rates of 200 to 300 barrels of oil per day, each for a combined rate of 650 barrels gross per day. We have added about 6,000 net acres to our leasehold position so far this year, bringing our total to approximately 35,000 net acres in the play.

We're in the process of acquiring another 20 square miles of 3D data and expect to have data in hand in the third quarter. We've identified 14 additional targets on our existing 11 square miles of 3D and are preparing to drill four of these locations within the next few weeks. This will be followed by another four Trenton/Black River tests later this year.

And last, I would like to highlight some of our emerging shale plays. As you may or may not know we are in various stages of progress on 9 different shale resource plays across the United States. We have already discussed two of these. The Williston Bakken and the Arkoma Woodford and we will highlight a couple more here as well.

To begin with, we have accumulated approximately 64,000 net acres targeting the Woodford in Atoka and the Anadarko Basin of Western Oklahoma in the Texas Panhandle. Now I wouldn't talked about these two plays before preferring to keep things quite while we accumulated a large lease position, but those of you who follow EOG Resources are probably aware of their recent announcement of 400 Bcf of reserve potential in the Atoka on their 60,000 net acres in the Texas Panhandle and our two recent completions was tested about 7 million cubic feet of gas a day each.

We like the reported results until this goes very well for our Atoka Bridge. We are very exited about this emerging opportunity, which is in our backyard. Our team of exploration has identified this opportunity about a year ago and we currently own 29,000 net acres and what we consider to be the Atoka Fairway and will begin drilling our first horizontal Atoka test this month.

We will also be doing some science on this well, including cutting their core to valuate the reservoir in more detail to get a better handle on the upside potential for this play. We also control 35,000 net acres targeting the Anadarko Woodford shale and plan to be drilling our first well by midyear. Both the Anadarko Woodford and Atoka gas shale plays are gas plays, where we expect to unlock new reserves applying the same drilling and completion technology used in the Arkoma Woodford and we expect similar economic results.

In the Appalachian basin we have agreements in place to acquire approximately 36,000 acres targeting the Lower Huron and Rhinestreet shale in Ohio. Title was currently being checked and we expect to close on this purchase later this month. The Lower Huron is known is a no producing subnormally pressure shale that gets up to 220 feet thick on our properties and we plan to drill four horizontal Huron tests on this acreage soon after the purchase is complete.

Moving on toward our 67,000 net acres in the Marfa Basin located in Southwest Texas our partner TXEO was successful in refracing the Simpson 1 vertical reentry and established production rates in the range of 150 to 300 Mcf a day from fracture stimulated Barnett shale. I might stress this was not a horizontal test.

We are encouraged with the results and are jointly designing our 3D seismic survey to evaluate a portion of our acreage would be intent to drill grass-roots horizontal Bakken or Barnett shale test later this year. We are also investigating the trusted portions of our acreage block for the potential opinion type opportunities. We are currently moving up hole in the Simpson 1 to test other behind-pipe zones and should have it done here in the next month or so.

In closing, I also want to add that we have budgeted $27 million for leasing in the Lower Huron, Marcellus plays in Pennsylvania, West Virginia and New York as well as the Haynesville in North Louisiana and we are actively leasing in this place.

Thank you. With that I will turn it back to Warren.

Warren Henry - Vice President of Investor Relations

At this time we are ready for Q&A.

Question And Answer

Operator

[Operator Instructions] And your first question comes from the line of Subash Chandra of Jefferies & Company. You may proceed.

Subash Chandra - Jefferies & Company

Hey, good morning guys. Congrats, looks like everything is working. In the Woodford Shale, what was the cost of the wells in that pilot?

John D. Hart - Vice President, Chief Financial Officer and Treasurer

They were around $4.6 million a piece.

Subash Chandra - Jefferies & Company

Okay. And that was in Ashland?

Harold G. Hamm - Chairman and Chief Executive Officer

That is correct.

Subash Chandra - Jefferies & Company

And when you think about sort of the opportunity to…well two questions. First is, of your program to-date, how many wells, how many acres do you have more than one penetration in, per square mile?

Jack H. Stark - Senior Vice President of Exploration

Actually our Williston 2 was the first one at the end of last year and as pilot was the next, well we had two…two additional wells in…the pilot was 6-12 wells, two additional wells and one 640, two additional wells in the adjoining 640.

Subash Chandra - Jefferies & Company

Okay. So, something like three factions out of your total number have seen more than one penetration.

Jack H. Stark - Senior Vice President of Exploration

Exactly.

Subash Chandra - Jefferies & Company

So, when you think about the repeatability of this in the McAlester area and the Salt Creek area then of course in the Ashland area. Do you dare to dream at this point and possibly thrown out what's you think, the number of locations might be your best guess at this point for total Woodford locations?

Jack H. Stark - Senior Vice President of Exploration

Yeah, I think…we actually give a number that's based upon 80 acres spacing, and of course you know that the new field is taken a down to 40 acres and we don't…

Jeffrey B. Hume - Senior Vice President of Operations

We are actually one of their pilots and from what we see, in their 40 acre test, it looks as good as 168 acre test that we just see it. But, in terms of net locations about 560 applications [ph].

Subash Chandra - Jefferies & Company

Okay. And do you think you try a 40 acre pilot, because I mean, the way Newfield sort of talks about it, they still – they're is still talking about trying to figure out optimal spacing, whether they need to go to 40s or something bigger might work. When do you think you might do a 40-acre pilot if that's in the cards?

Jack H. Stark - Senior Vice President of Exploration

I don't think we have really the plans at the moment, we just haven't – we're so, our interest is not really densely drill at all and I think we're setting up our program for the pinch over, further infield, but at this in point time we'll be doing probably three 20s and one 60s for the most part.

Subash Chandra - Jefferies & Company

Okay. Two more and I'll get back in the queue. The fourth well in Michigan, I guess you referenced three completed wells. Is the fourth well awaiting infrastructure?

Jack H. Stark - Senior Vice President of Exploration

You know we had three operated wells. We'd actually participated in two non-operated to the west of our play in what is called the Dog Leg prospects. The young well was the first one that was drilled there and we're still testing that wells. It's actually making more gas than oil. At the end the Pageant [ph] was the second one and I guess, the initial results I have right here and this was as on Friday, is that they just perpetrate the lowermost zone there and we're making ten barrels of water per hour, and just don't have any oil resources. I suspect that we'll continue testing that, move our pole in that well. But this particular project is not operated by us as I mentioned, but we are encouraged that we have had some more gas shows in the two wells. It's a quite a waste from the Albion-Scipio trends. So I think it does certainly show that the 3D seismic is working, our aerials maps [ph]is working, but we'll have to just see how these two wells work out. We've got about 50% interest in these two wells.

Subash Chandra - Jefferies & Company

So that Dog… so that Dog Leg prospect, was that 20 mile step-out area?

Jack H. Stark - Senior Vice President of Exploration

Correct. Exactly.

Subash Chandra - Jefferies & Company

Okay. And one final one, in your own words, this Haynesville area, what gets you excited about wanting to pursue acreage out there? I mean, you hear some ridiculous numbers, it even looks like Royalty is going for 9000 an acre and stuff like that. So what makes you want to get involved at this stage of the game?

Harold G. Hamm - Chairman and Chief Executive Officer

Obviously, Subash, I think it's the potential of the Haynesville itself. We see this thing having a big potential, and I think all of the industry does. Without a doubt, because it's one of the thicker, highly organic trails that we've encountered, and I think that's what's got everybody's attention. We, just like a lot of these others who rush to do and run some acreage prices up. We tend to get on the ground and dig up the acreage, and last time, we found out that we'd make a lot better deals in what's reported out there on the high ends that you hear about.

Subash Chandra - Jefferies & Company

Are there specific well results that have you excited?

Harold G. Hamm - Chairman and Chief Executive Officer

There is. The results that we've heard about, do have us excited. About of a couple of operators that's down there. So yeah, we think it's going to have really good potential.

Subash Chandra - Jefferies & Company

Could you cite what those results were?

Harold G. Hamm - Chairman and Chief Executive Officer

Well, we've seen rates over $7 million a day that's been reported. And…

Jack H. Stark - Senior Vice President of Exploration

When he says reported, I mean, it's really just sort of intelligence that we've gauged, we know the ground and so forth. I means it's not no real public report at this point in time. Sort of an aerodynamic [ph] of play --.

Harold G. Hamm - Chairman and Chief Executive Officer

I believe that's correct.

Subash Chandra - Jefferies & Company

All right. So results -- so Intel is $7 million a day on a whole bunch of owners, something like that.

Harold G. Hamm - Chairman and Chief Executive Officer

But its not a whole bunch of wells that's been drilled.

Subash Chandra - Jefferies & Company

Okay. So out of four? .Okay, enough said. So you can verify that there's been some good results down there.

Harold G. Hamm - Chairman and Chief Executive Officer

Yes Subash.

Subash Chandra - Jefferies & Company

Okay. Great. Thank you, I'll get back in a queue.

Operator

And your next question comes from the line of Monroe Helm of CM Energy Partners You may proceed.

Monroe Helm - CM Energy Partners

Great results guys. I am just kind of curious if you can share your thoughts if you've been able to analyze your USGS study and how it -- and what you may gleaned from that relative to your own assessment of the Bakken field because their numbers seem to be a lot higher than what most of the people in the industry were looking for I believe. So, you have any thoughts on those study and how it might relate to you, that would be interesting?

Jack H. Stark - Senior Vice President of Exploration

Yeah. If kind of look it [inaudible] to four or five smaller pieces it's done on the second page of the press release. Our acreage falls within the nascent big nine assessment units and that's one of the larger assessment units, since it about 900 million barrels within that assessment unit and of course Continental is the largest land owner in that particular assessment unit. I think at this point of time I think there are… numbers are probably a reasonable estimate at this point at time. If you also were to go out to the NDIC's website, you will see that the NDIC number for… this is just North Dakota's recoverable Bakken reserves. I think we are something about 2.1 billion barrels, which I think, if you look at the assessment by the USGS, is may be about 2.5 billion barrels. So, from two different approaches, and the NDIC did approach it differently, they came back to a similar number.

I think, as Jack said, I think over time, the number has grown from 150 million barrels to 4.3 billion barrels as a result of advances in technology. And I think as Jack said, I wouldn't be surprised if you see the number growing further. And I think our Bice wells is going to be… maybe a part of trying to figure out whether the number is higher as a result maybe of not counting incremental reserves that can be gained in the Three Forks-Sanish on our Nesson Anticline acreage.

Jack H. Stark - Senior Vice President of Exploration

And I might add too that we are not the only ones testing this Three Forks. And so, there is going to be multiple wells coming out from various operators out here. We will see some results. So, the potential added value from these Three Forks will start showing, I don't know, some results here as the year goes on.

Monroe Helm - CM Energy Partners

Okay. Just as a follow up, do you know what the USGS or the North Dakota estimates are, I assume, for the amount of oil rig in place or what the recovery factor is and what recovery factor are you guys assuming in your bookings at this point in time or was it purely the same?

Jeffrey B. Hume - Senior Vice President of Operations

The USGS did not report an in-place number, so not possible to calculate what recovery factor they might have used. As far as our numbers, I mean at the… I think at 300,000 barrels per 1,280, I mean that would be --.

Jack H. Stark - Senior Vice President of Exploration

We are probably in the 3% or 4% recovery factor on that first well on the 1,280, Monroe. The… we are seeing… if you look through… I did an analysis of all the players in the field, what they are presenting at the NDIC, and you are seeing anywhere from 5 million to 9 million barrels of oil in place per square mile. You derive that. Take a 5 million. You have 10 million barrels in place in a 1,280 and take 330,000 barrels equivalent out of it.

Obviously, a very low recovery is going to really support these additional wells and also support us trying limbo-lateral out and the Three Forks trying to frac up through and harvesting the entire source of supply. There is a tremendous… we do know the oil is there. We have cores, logs on it.

The key now is to keep working with techniques. The entire industry is working on this on how to harvest it and gain that. I would think we'd at some point approach the 12% recovery factor on the spacing in it to 15 on primary, 12% to 15% primary, which is a tremendous amount of oil.

Jeffrey B. Hume - Senior Vice President of Operations

And I think this uncemented liner completion technique, I mean you saw… heard the results of the Pleaton well there in the Rocky. I mean that's… it maybe that our reserves model, we moved up from 300,000 barrel average to maybe a higher number. Last year, our actual average was 335. It may… we are all poised to beat that this year. Hopefully, we will be in the 4% to 5% sort of recovery factor in our initial wells.

Monroe Helm - CM Energy Partners

Great. Congratulations again.

Jeffrey B. Hume - Senior Vice President of Operations

You're welcome.

Operator

And your next question comes from the line of Tom Covington of Broadpoint Capital. You may proceed.

Thomas E. Covington - Broadpoint Capital

Good morning, everybody. A question on the Sanish. How pervasive it is what you consider to be good fracture stimulations sort of Sanish sands across your Nesson Anticline acreage?

Jack H. Stark - Senior Vice President of Exploration

Yeah, the Three Forks-Sanish, it's a rock… a reservoir rock that exists throughout the Williston Basin, and it underlies the lower Bakken Shale. It's really no different in its distribution than the middle Bakken itself. So, its just one added reservoir rock in connection with these highly organic and thermally mature Shales that can hold oil.

So, the potential for this if it acts as a separate reservoir could potential double the recoveries, the reserve potential play. But that still remains to be seen whether or not these existing wells are communicating both reservoirs or not. And where the reservoir gets very thick, where the Bakken gets very thick, it seems unlikely that the two would be communicated.

Jeffrey B. Hume - Senior Vice President of Operations

And I would say, Tom, that to the extent the middle Bakken has been broken up due to some tectonics, I mean the Sanish would have been subjected to the same sort tectonics.

Jack H. Stark - Senior Vice President of Exploration

Yeah, without a doubt. And we particularly… we took our acreage position up along the Nesson Anticline for that specific reason. We feel that the tectonic history of that area are very just ideal for fracturing this reservoir rock. And so, it's just one of those things.

And I think that people tend to think that maybe these things are fractured independently from one another, and there are some arguments that can be made for inter-formation of fracturing and what have you due to hydrothermal or hydrocarbon generation, but I do believe that the tectonics are an overriding factor in here and Nesson Anticline is an ideal location for getting the reservoir fractured.

Thomas E. Covington - Broadpoint Capital

So, the key issue is how much of this upper Three Forks/Sanish can be saturated with Bakken sourced hydrocarbons essentially, given its fairly ubiquitous across the Nesson Anticline area.

Jack H. Stark - Senior Vice President of Exploration

Correct and actually, we've seen cores, and we participated in taking cores and then also other groups taking cores together, and we've seen saturation in the Three Forks from the south end of the Nesson Anticline to the north end. And so, there's really no question as to whether or not it's got oil in it. The question is, is it acting as a separate reservoir and it so it's added it to the recoveries and the rates we're seeing.

Jeffrey B. Hume - Senior Vice President of Operations

And I think, just to expand on that, when he says acting as a separate reservoir, is it's not in communication with the middle Bakken after we fract it.

Jack H. Stark - Senior Vice President of Exploration

We would drill in the middle Bakken in many areas especially along our acreage along the Nesson, we're 50 there. 80 feet above the Three Forks, where we are putting that horizontal wellbore in the middle of Bakken shale…middle Bakken dolomite sand aversion in character. And so, the question is, are we communicating with that zone, sitting that much further below us, and arguments can be made both ways, but right now, our indications are that, and our expectations are that in these thick areas, we're going to see it acting as a separate reservoir.

Thomas E. Covington - Broadpoint Capital

And there's not much incremental capital to obviously go down another 100 feet or so?

Jack H. Stark - Senior Vice President of Exploration

No.

Thomas E. Covington - Broadpoint Capital

Would you consider looking at dual laterals if these are indeed separate reservoirs, as we go forward?

Jeffrey B. Hume - Senior Vice President of Operations

Tom, I think that's something we'll absolutely be looking at in the future. I think the first course of business though is to identify, can we open both of these with one lateral, hopefully drilling in this Three Forks, the frac will move up and we can properly stimulate it up through, and get the entire source of supply out of the Bakken, which goes from the upper Bakken shale down through the Three Forks/Sanish zone.

If we find that we can't effectively stimulate that from a horizontal wellbore, you got to remember we're planting a six inch hole down there, perhaps 150 feet below the top of the source of supply. It may require dual laterals and I think you'll see us migrate to that in time that starting out I think we have to drill some single completions and three, four attempt to frac up through the entire system, produce it probably come in behind it, drill a well above it, see if we've affect the drainage on the upper and make the decision at that time and it is mechanically feasible to do that, it will be an additional cost to it of course, but for additional reserves. So, it would be something we would.

Thomas E. Covington - Broadpoint Capital

On the Atoka play give me a…help us to think about this play in terms of spacing and what kind of lithologies are we really looking at in terms of this reservoir the 29,000 acres out in the West Texas Panhandle area.

Harold G. Hamm - Chairman and Chief Executive Officer

Obviously we're started working with this play. Our people came up with the idea that there is a lot of gas coming out of the few feet of sand and probably too much in fact and that's what got us on this thing and we intend to drill these first well…our first well on 640 acres spacing, where just kind of following suit some of the operations is over in the Texas side with the, our first well in Oklahoma and follow the success that has already been out there.

Jack H. Stark - Senior Vice President of Exploration

Like I said, we got about one-third of our acreage in the Texas Panhandle and about two-thirds in Western Oklahoma just on either side of the border.

Thomas E. Covington - Broadpoint Capital

What kind of laterals lengths, where we would be looking at here?

Harold G. Hamm - Chairman and Chief Executive Officer

I think we plan a fairly long lateral length.

Jeffrey B. Hume - Senior Vice President of Operations

It will be 4,500 to 5000 feet starting out and we'll just have to play it ear on what our drainage looks like I do think there will be increase density opportunity after we see net effect of the first few wells drill.

Thomas E. Covington - Broadpoint Capital

What kind of capital cost are you looking at?

Jeffrey B. Hume - Senior Vice President of Operations

I believe those were around $4 million…$4 million to $4.5 million. I don't have that in front of me right now, but I can get that to everybody.

Thomas E. Covington - Broadpoint Capital

Okay. Thank you very much guys.

Warren Henry - Vice President of Investor Relations

Thank you.

Operator

And your next question comes from the line of Eric Hagen of Merrill Lynch. You may proceed.

Eric Hagen - Merrill Lynch

Hey, good morning, on the…back to the North Dakota Bakken, in terms of the multistage fracs. How many wells we completed with that new process, and can you quantify the results to-date maybe increases in IPs and how might that translate into EORs per well?

Jeffrey B. Hume - Senior Vice President of Operations

Well, we have finished actually five, I've done two with sleeves and three with perf and plug method. We feel like the perf and plug method we're getting better zone isolation and getting better rates of sand into it. Those wells have what we've seen on those is IPs in the Florida as we've mentioned this morning the 700. I am talking seven day IPs what we've try to go by here instead of taking an instantaneous one day, but 400 to 700 plus barrels a day IP in that almost goes into an EOR we're looking at 400,000 to 700,000 barrels EOR versus the 335 that we've seen before. And I feel like we can get that still very early to be forecasting EOR on these new completions --.

Harold G. Hamm - Chairman and Chief Executive Officer

Yes, we've been hesitant to do that until we had a little bit bigger dataset.

Jeffrey B. Hume - Senior Vice President of Operations

We need to shape in the curve, and to see what its doing, but obviously we are affecting more rock, we are getting the initial IP being higher you are affecting more rock, and we expect to see similar type decline curves than we're seeing on the others. But, I think Hagen in multiple transfers, fracs through there and the amount of area we are covering, is going to prove…

John D. Hart - Vice President and Chief Financial Officer

I might say that it is costing just a little bit more, and these are probably 5.2 or so.

Harold G. Hamm - Chairman and Chief Executive Officer

That's correct.

Jeffrey B. Hume - Senior Vice President of Operations

And the bulk of that is, just the time spent fracturing it with the plug and packer method we are spending four to six days on the frac to do that, specially winter time, it is very costly in the summer, I think we will improve that greatly. But we are dealing with fresh water simulation fluids in the winter time, that's just slows you down.

Thomas E. Covington - Broadpoint Capital

You have seen, whether operators of that drill, two wells per section on these permitted [ph] laterals. Are you considering that as well, in terms of spacing?

Harold G. Hamm - Chairman and Chief Executive Officer

I think, I mean, our Consortium project that we are in with Headington, actually we have two wells in a sort of 1280?

Jack H. Stark - Senior Vice President of Exploration

This is 640.

Harold G. Hamm - Chairman and Chief Executive Officer

640, so we got two wells on our 640. And a third well actually in the middle that's serving as a moderate well that we'll put in production in the future at some point of time. And I think, we understand, some other operators are drilling 320-acre spacing wells. So, some of that is going on in the Bakken. Certainly.

Thomas E. Covington - Broadpoint Capital

And the last one, just on the, Three Forks, can you give us any indication of how many wells been drilled by industry into the Three Forks and possibly any results. I think we've have heard of the Petro-Hunt well,. Have there been any incremental wells post that or…?

Harold G. Hamm - Chairman and Chief Executive Officer

Probably they're just handful right now, I would say, there is five in the various stage of drilling or completing. Some of the initial rates they may not have, may be haven't even been reported yet, but through our discussions, we kind of come we're very too what we're seeing in the Middle Bakken completions and that's what we would expect. We'd expect that rock to perform similarly. Its character and its nature is very similar to the Middle Bakken. In many respects it does vary in character across the basin, but in generally you can say it's a kind of a lower permitine n time rock that's fractured in and the saturation within that does look good what we've seen in course. And so, its not surprising that the results look like what we've encountered in the Middle.

Thomas E. Covington - Broadpoint Capital

Great, thanks.

Operator

And your question comes from the line John Freeman of Raymond James. You may proceed.

John Freeman - Raymond James

Hi, guys.

Harold G. Hamm - Chairman and Chief Executive Officer

Hi, John.

John Freeman - Raymond James

On the Woodford Shale, I just want to make sure that I've got this right. On the pilot program you did, the 4 million completed well costs, is that apples-to-apples with the 5 million you've typically spend on the Woodford?

John D. Hart - Vice President and Chief Financial Officer

It is, 4.6 I think…

John Freeman - Raymond James

Oh, 4.6, okay. And the reduction is just on the drilling days primarily, and I think it was cited drilling days are down 22% on the pilot?

John D. Hart - Vice President and Chief Financial Officer

That is correct. We're getting that time down and it's a pulling our cost down.

John Freeman - Raymond James

Okay, and then has there been any change to the original kind of per barrel operating cost guidance that you have provided for '08 back in November or is that still the same?

John D. Hart - Vice President and Chief Financial Officer

That's still the same. We still feel comfortable with that range.

John Freeman - Raymond James

Okay. And then, are there any plans down the road to look at employing CO2 floods in Montana?

Harold G. Hamm - Chairman and Chief Executive Officer

We continue to investigate that. We've taken some fuel examples. Jeff, you like to talk about?

Jeffrey B. Hume - Senior Vice President of Operations

Yes, we have some slim tube test back. As we'd anticipated it has excellent displacement recovery of the oil in place through a slim tube, and we have different disability pressures and recovery rates from that work. Right now, we're planning a… in the initial stages of planning a pilot program that we'll be presenting to a consortium of operators up there. That we have a group that's working on that project, and depending on the outcome of our next meeting with the group, we hope to have some sort of test later this year, where we'll physically pump either CO2 or water into a pattern in the Montana Bakken M. Cooley [ph] field and give that an attempt. But that is totally dependent upon the court consortium and is out of control at this time, but we are working towards it, and all members of the consortium are aggressive in wanting to try our way to flooding the [pie] and hence recovery to that field.

Harold G. Hamm - Chairman and Chief Executive Officer

Yeah, and we've also been in discussion with some potential source of CO2 nearin? the area.

Jeffrey B. Hume - Senior Vice President of Operations

That is correct.

John Freeman - Raymond James

Okay. And then, are there any plans to significantly increase the number of frac stages in the Bakken? I know there's some talk by some of your competitors, talking about doing possible even as much as 20 stage frac?

Harold G. Hamm - Chairman and Chief Executive Officer

You know, that's possible. I've heard of some operators getting very close on spacing. I don't have verbiage at this time. I don't have data in front of me. Mark mentioned a consortium that we're a member of, that heading wells and operator of, we're going to be looking at some fairly dense spacing in that -- 640, I believe we eight stages in our 640 lateral, which will be equivalent to…

Jeffrey B. Hume - Senior Vice President of Operations

He was talking about the Woodford.

Harold G. Hamm - Chairman and Chief Executive Officer

Oh, the Woodford?

John Freeman - Raymond James

No, no, the Bakken.

Harold G. Hamm - Chairman and Chief Executive Officer

Oh, I'm sorry. Okay. So

Harold G. Hamm - Chairman and Chief Executive Officer

And so, you know, that would be equivalent to a 16 to 18 stage. And I think that's, John, that is just going to be something that revolves over time what's the optimum density to have right now from a recent well, the Pleaton. We set it up for 10 stages. I think we can physically add stages to it. I think we can get up to the 16 to 18 stages physically without a problem.

When we'll try that, I can't tell you. I think we want to assess the results of these 10 stage job right now. So, as we said earlier, it takes anywhere from four to six days to carry out one of those. You double those stages, we're going to be time fracture it up for almost twice that long. So, you're looking at…you need a tremendous amount of equipment to carry out those many stages. But, the industry as a whole keeps pushing the edge on that. We're going to optimize that over the next year, year-and-a-half.

John Freeman - Raymond James

Okay. And then last question I had, just making sure somebody knows it right from past call, on the Haley prospect, is around like 2.4 million completed well cost still accurate?

Jack H. Stark - Senior Vice President of Exploration

That is correct.

John Freeman - Raymond James

Okay, great. Thanks. Great quarter, guys.

Jeffrey B. Hume - Senior Vice President of Operations

Thanks.

Operator

And your next question comes from the line of Joe Allman of JPMorgan. You may proceed.

Joseph Allman - JPMorgan

Hey, good morning, everybody.

Jack H. Stark - Senior Vice President of Exploration

Hey, Joe, good morning.

Joseph Allman - JPMorgan

Could you… on the [inaudible] Bakken, I think you have 10 rigs running now. I know you're ramping up the rig count there. Can you just clarify that?

Jeffrey B. Hume - Senior Vice President of Operations

We have 10 in the Bakken.

Joseph Allman - JPMorgan

In the Bakken, okay.

Jeffrey B. Hume - Senior Vice President of Operations

Four in Montana and six in North Dakota operated.

Joseph Allman - JPMorgan

Got you. And you're going to ramp up to 12 and then the 13. And I guess, those incremental will be all in North Dakota, Bakken.

Jack H. Stark - Senior Vice President of Exploration

Correct.

Jeffrey B. Hume - Senior Vice President of Operations

We ultimately expect to have 3 in Montana and the rest 10 in North Dakota.

Joseph Allman - JPMorgan

Got you. That's helpful. And then of the six that are operating in North Dakota, are they all using sort of the newer drilling and completion techniques or is it still a mixed bag of techniques now?

Jeffrey B. Hume - Senior Vice President of Operations

No, we've gone to this technique on all the wells, and we're going to stay with that till we see something better come along.

Joseph Allman - JPMorgan

Okay, got you. And then it appears to me that just based on the data you gave this morning and in your press release that you're just… most recent wells are somewhat consistent with kind of the immediately prior release, but you're definitely seeing it… as time goes on, we are seeing an incremental improvement going forward. Is that correct?

Jeffrey B. Hume - Senior Vice President of Operations

We think we'll see an improvement, yes.

Joseph Allman - JPMorgan

Okay, got you. And then in Montana, I mean can you talk about anything else and anything new to report in Montana? You said it's consistent with your expectations. Anything good, anything kind of disappointing there?

Jeffrey B. Hume - Senior Vice President of Operations

LeaJoe was the well that's in the press release, which is one of the better wells drilled in the Bakken, of course, since yearend. That well… you might talk about that, Jack, about that well?

Jack H. Stark - Senior Vice President of Exploration

Yeah, there was just an inter-unit well there that was drilled on two larger spacing units at the rate of 180 acres a piece actually. And the completion there itself, again, it was a single-leg completion going across that essentially the unit boundary. So, it was a very nice completion in there. And we also have had success again or continue to have success with our tri-laterals.

We are very happy with sort of the results of our Pennie well. There is 348 barrels a day. That's a tri-lateral up in an area that previously we thought was marginal to sub-economic. And so, we just continue to… we're going to keep drilling those until we find that it is working.

Jeffrey B. Hume - Senior Vice President of Operations

Yeah, I'd like to say, in Montana, in our infields, now we are going to this liner completion as well, and you might talk about that, Jack?

Jack H. Stark - Senior Vice President of Exploration

Yeah, that's correct. We've… on these infield wells, we've been running drilling the long single lateral and running the liner completion where we are going to experiment with multiple stages. We did one with a micro-size on it. We've got good results from the… we feel like better fractured distribution from the micro-size. We saw when we did it pre-perforated liner and 12 packers.

And as we drop ball sealers to seal off different zones and divert, we saw micro-size activity change in the formation. That is still being processed right now, but we feel like that's going to improve the drainage in the Montana Bakken area as we move forward. So we are… the next several wells we drill in Montana Bakken, we are going to run the packer and multi-stage frac and see if we can improve our results there.

Jeffrey B. Hume - Senior Vice President of Operations

And, Joe, as you may and I am sure you recall, I mean we had previously drilled these Montana wells with dual laterals. So, one mile, rather than two mile single, long laterals now and they are all open-hole completions. So, this is change in the style and we hope that it will provide better results.

Joseph Allman - JPMorgan

And then back to North Dakota for a second, so pretty much all the wells you are drilling now are just longer single laterals?

Jack H. Stark - Senior Vice President of Exploration

That is correct. They are about 9,000 to 9,500 foot long laterals, 2 square miles, 1,280-acre units.

Joseph Allman - JPMorgan

Okay. And then still North Dakota, I mean previously you would drill a bucket of wells there, groups of wells, and you have a few that are non-commercial, but on average, it will be very economic play. Are you seeing… are you still seeing some uneconomic wells and just on average the whole program is improving or are you finding pretty much everything is improving and no more uneconomic wells.

Jack H. Stark - Senior Vice President of Exploration

No, I think we are seeing everything improving. And part of that is we are getting consistent completion technique. The earlier wells the once that we are sub economic most all of that those had mechanical problems, and we were trying different things…we took the dual lateral technique from Montana over the North Dakota. We had quite bit of evidence that we were not getting the frac to distribute up down wellbore, when we went to clean it out, we found the junction, where we turn the lateral north and south was caving in.

So, we're having some problems there. And, we alleviated of all that…with eliminated all with the case liner system in multistage and we've done several of these in row now. The crews up there are getting very good at carrying out this type of completion, I think we will just see that prove in time as we do more and more of those and the last several wells we've done that way we mentioned earlier, we feel like…I don't see any poor wells right now just improving on our base.

Joseph Allman - JPMorgan

And in terms of your acreage position two things. One, have you increased your North Dakota Bakken acreage since the last disclosure? And then, two previously you said you wouldn't sell any of your acreage, do you still hold to that or are you honing in on area that are working. And you're just avoiding some areas that you think even with an improved drilling in completion technique probably still won't really work?

Jeffrey B. Hume - Senior Vice President of Operations

Joe, we've added 66,000 acres since December 31 and Tom Luttrell, he is Vice President of Land. He says that North Dakota 50 back. The 50,000…and we've added that principally along the Nesson and then in the Southeastern part of our holdings and in the end sort of the Northeastern part of our holdings, sort of expanded those positions. As far as…we haven't condemned anything in our mind, in our holdings and have really not let any significant acreage expire. And as we outlined this liner completion technique…we've only done five of this. Pleaton was the very first one in the Rocket and until we get some of those tests done this way, we still think everything we own is prospective.

Joseph Allman - JPMorgan

Okay. I've got some more, but let me get back in the queue.

Jeffrey B. Hume - Senior Vice President of Operations

Okay.

Operator

And your next question comes from the line of Subash Chandra of Jeffries. You may proceed.

Subash Chandra - Jefferies & Company

Yeah. Back to the Woodford here, so at this point, what do you see, really the primary characteristics to making the Woodford work throughout in improving the EOR, it looks like, these well costs are coming down, and a lot of other operators also staying out of trouble, and delivering on some like $5 million well cost. That appears to be a mover here, but do you think thickness and things like that, can you run down a list of what's you might think is critical? And second is, the Chesapeake acreage…any desire at this point to build out your acreage position? Does it look like there's a whole lot of available out there, unless Antero comes out, and any thoughts on that?

Jeffrey B. Hume - Senior Vice President of Operations

Yeah. I'll let Jack talk on the…3D seismic was one element in the Woodford…a lot of us get out there and head to drill wells early without the benefit of a lot of information. And so, I think some of what you're seeing in way of improvements is…we've got the 3D, we've drilled some initial wells, we've learnt what works and what doesn't work.

Jack H. Stark - Senior Vice President of Exploration

Yeah, I think your question has a couple of directions to take this but I will talk to specifically geology. As far as thickness is concerned and is significant, I think the jury is still out on that. It's hard to say. You need to be greater than 50 foot. We initially just had in our mind a 50 foot cutoff, just really no real true basis for that except just we needed to see more and more results. And at this point I don't know that you can't do less…50 foot or less and make a commercial well out here.

Generally, where you see you it get thinner, you getting shallower, so your economic change, what have you so it's hard to put a box around and say you need X amount thickness, number one. Number two, you have fracturing in the area. As Marks said you really need to be able to identify and define where you're going to drill with 3D. It's very helpful because you do want to stay away from the faults, but the bigger faults. The smaller ones you can identify and drill across and case across and go ahead and complete and exclude those areas, on your completion and not lose your frac or the fault zone.

So, 3D seismic plays a big part in identifying and tracking those fractures and so and then on top of that there is always, there is risk of what is the zone below you, like down in the Barnet there was concerns and there were problems with water coming from lower zones and here the area until you get more data you're not sure exactly what zone is below you, but we with well control that exists, the acreage we've got is an areas we feel we don't have much concern about a wet hunting zone underneath us here in this particular area.

Mark E. Monroe - President and Chief Operating Officer

And I think we've learned a little bit more about the orientation of the fracture system in areas, where we were drilling and that's real important.

Jack H. Stark - Senior Vice President of Exploration

Well, yeah and they really did, doing the micro size work, definitely helped confirm the 3D seismic interpretation and 2D seismic interpretation has been done out in here as to where the primary directions of fracturing are, what the orientations are. And so it just helped confirm what we were doing and how we're going about this and, so we drilled one of our wells last year parallel to that fractured orientation, it didn't turn out to be so good. So we since decided we won't do that again because with the number of fractions you cut. And but it was borne out by the work we've done. That's right and so shooting 3D right now in our Salt Creel area and we think we are going be able to improve our results up in that area. Just by… we did not have that previously the drilling up in there. And so I think it's going to help our results.

Mark E. Monroe - President and Chief Operating Officer

Actually, I mean as we study the results I think the wells were actually turning the corner a little bit maybe seeing it to be little bit flatter than the typical curve would have been. And so we're…I think that holds promise there and certainly East McAlester, I mean, I think there's been some other operators drills some very nice wells. It's kind of near our acreage and we are very bullish about that particular acreage block that we have there.

As far as drilling out our position, I think it just not lot of opportunity other than making acquisitions and we've have got a lot of things in our play to do elsewhere that, I just don't see as being tremendously aggressive trying to buy someone out of the Woodford acreage.

Harold G. Hamm - Chairman and Chief Executive Officer

And I think that's true I think the acreage is good and it's appears in good areas and all that but you just have to assess and as what Mark said acreage is scarce over there. There is not any more of it. So a word to point when this become very expensive in these plays. We have several of them going on and probably could use that same money else where?

Subash Chandra - Jefferies & Company

You participating in those extended laterals and you feel that… any comments on sort of what you think those extra dollars are worth much, and when you might try such things on your acreage. So your desired to maximize lateral length and then, and then finally the, I guess the Hutton [ph] distribution how does that vary across the Woodford. The only thing I have heard possibly is that the, in the south-west area, might be missing but it's might be pervasive, much of everywhere else.

Harold G. Hamm - Chairman and Chief Executive Officer

Actually the Hutton, we wish or kind of condense in one area, there to the south west part and where the Hutton was present and possibly Wharton [ph] were in the same areas. We don't see it pervasive across the area at all. And as to, the lateral lengths we actually consider these fairly short. You know, with the lengths that we have been drilling and particularly in the Bakken and so, we came back to Oklahoma we were or come back here in this Woodford play, we started out drilling 4000 foot laterals. So, fairly long laterals to start with and, really we didn't see all that much difference in cost.

Jeffrey B. Hume - Senior Vice President of Operations

You know I think we were cutting them short was because of what we are seeing in the way of sink holes or fractures holes [ph]. So I mean we were trying to get out as far as we could from the get going.

But to us it just makes logical sense to, drill longer if you think you are going to have 5-600 Mcf a day per 500 foot frac job, you know you want to get as many of those jobs and as you can..

Subash Chandra - Jefferies & Company

And North Dakota, so despite the sales on these incremental wells with the additional rigs since you are going into lease retention, how can you sort of comment on what we can expect?

Harold G. Hamm - Chairman and Chief Executive Officer

Spud TD is about --.

Jeffrey B. Hume - Senior Vice President of Operations

Yeah, we have one spud TD in 28 days and that's going to be our model to be. But I'm going to say, we're going probably average around 40 days… 40 days to 45 days spud to spud because after we TD we have to reign these out on the liners. So it takes little time when the rig moves. So we're probably looking 40, 45 days there. And we are going to try to have them on 30 days after that rig really start to have them fraced and on. So we're going to be in the 75 day to 80 days turnarounds and be working on bringing that down as time goes on.

And I think in the summer months, you'll see us turning those around a lot faster we will in the winter months which is due to logistics and dealing with the fresh water frac fluids. As I said, we just finished a ten days frac in four days. We've only done four of those plug and packer. So, its proving very fast and that just working daylights. So that's not working around the clock. So we have a limit on how long you can work men, time loss per DOT standards. I think spud, what we're going to see is if we can get the frac crews in there and lined up and they are moving into the basin I think it would be adequate coverage to handle the accelerated rig growth and handle it. So, I think 75 day to 80 day turnaround spud production.

Subash Chandra - Jefferies & Company

Terrific. Thank you.

Operator

And you last question is a follow up from the line of Joe Allman of JPMorgan. You may proceed.

Joseph Allman - JPMorgan

Okay, thank you. In terms of the Three Forks-Sanish, do you have any evidence that any of your existing producing wells you're getting some production from the Three Forks-Sanish? And also I think previously you said, that you think previously you said that you think the Antelope Field was actually producing primarily from the Three Forks-Sanish. Can you comment on that too?

Jeffrey B. Hume - Senior Vice President of Operations

Yeah, I would say that we can't say whether we're getting any contribution from the Sanish in any of our wells at this point in time. As far as the Sanish production, along the Antelope Field, you know, that was -- Jack?

Jack H. Stark - Senior Vice President of Exploration

I mean that's what the field was originally completed in. The first wells in there were producing --.

Jeffrey B. Hume - Senior Vice President of Operations

And they were vertical wells.

Jack H. Stark - Senior Vice President of Exploration

They were vertical well. And so… I mean there is nothing really new about the Three Forks-Sanish out here. It does produce. And we now know from cores, we see oil saturation in it. And so just the question is whether or not it's performing… it will perform independently of our horizontals in the middle Bakken or whether or not they're already working together in a system of fractures there. And we don't know that yet, and we're in the process of trying to prove that one way or the other.

Jeffrey B. Hume - Senior Vice President of Operations

And, Joe, I'd say, the Sanish vertical wells, I mean those were the best vertical wells drilled along the Nesson at that time with the Bakken completion. As they went back in and tested… as I understand, as they went back in and tested the Bakken and some of those wells, they found that they were depleted at the Bakken.

So, I think those were better wells, because they were… they had some associated major tectonics in there that allowed them to produce both the Sanish and the Bakken from one completion. And that's why we're excited about the potential where we don't have major tectonics that would allow these to be communicated.

Joseph Allman - JPMorgan

Okay. That's helpful. And then moving over to the Trenton/Black River play, you guys are just… I think you're going to start your first well coming up here pretty soon, operated for 2008. So, you got three operated already, good results in a constrained production. Is it just waiting for the 3D that's prevented you from starting this program earlier?

And then I think previously you said you had 10 prospects. And now, I think it's looking like 14. Could you just comment on that? And then how many wells would you expect per prospect assuming that success?

Harold G. Hamm - Chairman and Chief Executive Officer

Well, yes, we're starting now up there with additional wells. We… our delay has been due to the frost laws up there in Michigan, so we couldn't move heavy equipment, rocket drilling rigs. So, we've held off. But right now, we have five wells that's currently scheduled to move the rigs back in. So, we should see additional results fairly quickly.

Mark E. Monroe - President and Chief Operating Officer

And the number of prospects really vary or a number of opportunities really vary kind of on your interpretations, the seismic and kind of grade them out as here are my top 'X' number of prospects and so on so forth. So, the number is going to move around somewhat. This is really interpretive as to what's the number of opportunities you have.

And right now of the two shoots that we've been involved in, which really only cover about 10% of our acreage, we've identified 14 opportunities. And I think that would translate in the 14 wells if we have success. I think that would be unlikely that we're going drill all of them out and have all them successful, but that's at least the number of opportunities we have.

Joseph Allman - JPMorgan

So, Mark, you're thinking one well per prospect?

Mark E. Monroe - President and Chief Operating Officer

That's kind of the way we'll see it right now.

Joseph Allman - JPMorgan

Okay. And then just moving over the Atoka, so is that in fact a shale, because I'll have to go back to the transcript of EOG, but I am not sure if they called that a share? And then you said something in your comments about a Fairway… being in the Fairway. I mean are you kind of in the middle of where they've got their acreage?

Mark E. Monroe - President and Chief Operating Officer

We are… we feel like we are in Fairway. This is a basically a Shale bounded sand and for the most part. So, we drill within that portion of that sand that we can and obviously we're going to be fracing out in that shale around it and that's supply. We saw too much gas coming out the thin sand.

Joseph Allman - JPMorgan

Got you, and you're trying to accumulate more acreage that you are trying to do over there now.

Jack H. Stark - Senior Vice President of Exploration

We've held off talking about this for about a year or better so we continue to apply our acreage up there and got a nice sizeable mass of acreage at this point. But we will continue our efforts.

Joseph Allman - JPMorgan

And how many well reserves do you have out there at this point?

Mark E. Monroe - President and Chief Operating Officer

Well, we are just now starting our first well. But obviously EOG reported last week on several tasks they have and I think their number is, they have a good number of them drilled.

Joseph Allman - JPMorgan

Yeah, I think they announced 17.

Mark E. Monroe - President and Chief Operating Officer

I believe that was correct.

Joseph Allman - JPMorgan

And then in terms of the Woodford, so when you talked about the Woodford, so you talk that this is the Woodford would be a different play and different location and could you comment on that and give us what you can on in terms of where that Woodford is located.

Jeffrey B. Hume - Senior Vice President of Operations

It is…it's this thing started in the Woodford. And the Arkoma at least down around Canadian County Oklahoma. There have been a mass some acreage and we were in first well or two is very small interest and yet see that go forward though and the results we see are good and that's being continued. We are seeing a lot of people in there leasing acreage at this point and so we've been in the play quite a while gather acreage down there.

Joseph Allman - JPMorgan

Okay. And lastly, a lot of operators reporting that it's a different topic….just service cost, drilling and completion cost, the trend is that thing seems to be leveling off; previously they were declining; now we are seeing some leveling off. I know you guys are talking about efficiencies in different areas. Are you seeing the same thing or are you seeing cost rates leveling off, are you seeing any increases in cost, can you comment on that.

John D. Hart - Vice President, Chief Financial Officer and Treasurer

Joe, the only increase I have seen is just fuel charge adjustments and the moves, but for the most part they are pretty steady, the one area that we are getting pressure on, the entire industry is, steel prices, which had raise on steel price every month this year, continues to go up. There is a domestic shortage of steel. We have long-range very good relationships with both suppliers and the manufacturers and we are keeping close with them to meet our needs, but it's the raw steel both billet and flat rolled. That's shortage right now. I have seen a lot of in the worldwide commodity. We are seeing a lot of activity around the world, locking that down. A lot of the countries are just flat locking it down. And I believe Mr. Chavez nationalized one of the flat rolled plans last week or last month. So, that pressure is on, I am sure it will be alleviated in time. But, I think that's one area, where we are seeing pressures in the industry on higher prices, is steel.

Joseph Allman - JPMorgan

And in terms I know you ramped up your rig count. What are you seeing in terms of rig rates? Are you seeing them level off or increase from what you --?

Jeffrey B. Hume - Senior Vice President of Operations

We are pretty well holding on what we've had in the last several years. And, what we are doing on rig rates, are seeing a huge, really no changes.

John D. Hart - Vice President, Chief Financial Officer and Treasurer

Yeah, what Jeff says, last couple of years or so we didn't…our people we dealt with really didn't raise rates quite up high as others. And so, it's been reasonably flat. I would say probably our average rig rate is 17,000 to 18,000 per day.

Harold G. Hamm - Chairman and Chief Executive Officer

That's correct.

Joseph Allman - JPMorgan

Okay, very helpful. Thanks for your time.

John D. Hart - Vice President, Chief Financial Officer and Treasurer

Okay, thanks.

Warren Henry - Vice President of Investor Relations

We just had some closing comments from Harold.

Harold G. Hamm - Chairman and Chief Executive Officer

Okay, thank you all for tuning in today. I appreciate your interest and questions. As we've outlined this morning Continental's significant activity is a number of resource plays. We are planning to invest $78 million this year to grow our acreage position in this new and existing Shale plays. With crude oil trading well over $100 per barrel, we expect to have cash flows to fund a new $783 million capital budget and a $70 million in proved reserve acquisitions already closed this year.

And I think this is most exciting time in this industry and particularly for Continental that I've experienced at least in my 40-years of working in the industry. We not only have high oil and gas prices, but also tremendous opportunities and wish to invest these high cash flows. I really appreciate your participation in this call this morning. Thanks.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect.

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Source: Continental Resources, Inc. Q1 2008 Earnings Call Transcript
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