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Executives

J. Warren Henry - VP of IR

Harold G. Hamm - Chairman and CEO

Jack Stark - Sr. VP of Exploration

Mark E. Monroe - President and COO

Analysts

Thomas E. Covington - Broadpoint Capital

Subash Chandra - Jefferies & Co

Joseph Allman - JP Morgan

Sunil Jagwani - Catapult

John Freeman - Raymond James

Eric Hagen - Merrill Lynch

Continental Resources, Inc. (CLR) Q2 FY08 Earnings Call July 29, 2008 10:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Second Quarter 2008 Continental Resources Incorporated Earnings Call. My name is Eric and I'll be your coordinator for today. Now, at this time, all participants are in a listen-only mode. We'll facilitate a question-and-answer session at the end of the presentation. [Operator Instructions]

I would now like to turn your presentation over to your host, Mr. Warren Henry, Vice President of Investor Relations. Please proceed; sir.

J. Warren Henry - Vice President of Investor Relations

Good morning, everyone and welcome to our second quarter 2008 earnings conference call. Today's call will include 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 all company statements included in this conference call, regarding the company's strategy, future operations, future production, estimated capital expenditures, projected costs and other plans and objectives of management are forward-looking information that speaks only as of today's date.

Although, we believe that the plans, intentions and expectations reflected herein as suggested by forward-looking statements are reasonable, there is no assurance that these will be achieved. Actual results may differ materially 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, 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 maybe filed with the Securities and Exchange Commission.

The format for this morning's call will be as follows: Chairman and CEO, Harold Hamm, will provide a brief overview of second quarter achievements and our opportunities for growth in the second half. Jack Stark, Senior Vice President of Exploration, will provide greater detail on recent developments, focusing on each of our key operating regions. At that point, we will be ready for Q&A.

Also available at that time will be Mark Monroe, President and COO; and John Hart, VP and Chief Financial Officer. Jeff Hume, our SVP of Operations; is not in his usual role on the call today, because he's traveling out of the country. With that, I would like to turn the call over to Harold.

Harold G. Hamm - Chairman and Chief Executive Officer

Good morning, everyone. Thanks for joining us on the call today. We are very pleased to announce record quarterly financial results for the second quarter of 2008. Total revenues of $303 million were more than double the second quarter of 2007. Crude oil and natural gas sales increased little bit more beating last year's second quarter by 113%. We also saw higher margins as EBITDAX increased 125% over the same period last year.

Net income was $127.3 million or $0.75 per diluted share, compared on pro forma basis to $44.2 million or $0.27 per share in the second quarter last year. The actual reported number of the last year's second quarter was a net loss of $142.5 million, reflecting a tax charge in connection with the conversion to a subchapter C corporation.

Average daily production was 31,623 barrels of oil equivalent per day during the second quarter of 2008, an increase of 5%over the first quarter of 2008 and an increase of 11% over the second quarter of last year. As we noted in the press release this morning, our June production rate was even higher just over 33,000 boepd, showing great acceleration during the quarter and a positive trend in line with our expectation for the remainder of the year.

We benefited from strong commodity prices as our average crude oil price was $118.28 and our average natural gas price was $8.82 per Mcf, for the second quarter of 2008. As we noted on our previous earnings conference call three months ago, our only crude oil has expired on April 30th. So certainly we have captured a full benefit of higher oil and natural gas prices.

We expect to remain unhedged, given the strength of our balance sheet and our outlook on commodity prices. We continue to be bullish on crude oil prices in 2008, 09 and beyond. As many of you know, an Oklahoma company of Sandburg [ph] filed for bankruptcy protection last week. Continental has no significantly receivables due from Sandburg [ph]. We have a small interest in a couple of oils operated by others; it may have sold to Sandburg [ph]. If that is the case, we may have small receivable due probably less than $1000.

Given our strong growth and cash flow performance, we announced in this morning's press release that we are increasing our operated drilling rig count and plant to request more pivotal for a second increase in our 2008 CapEx budget. We've raised our CapEx budget and to $783 million and our current internal cash flow projection is significantly north of that number. Consequently we intend to put additional cash flow to work in terms of more drilling rigs and addition raising.

This increased CapEx budget will enable us to have approximately 35 operated drilling rigs by year end, compared with the earlier expectation of 30. We have also continued to grow and develop acreage positioned in the Bakken, Anadarko, Woodford, Atoka, Marcellus, Rhinestreet, Huron and Haynesville Shale plays.

During the first half of this year, we invested $56 million in land acquisitions and increased our undeveloped acreage positions to approximately $1 million acres in U.S. shale resource plays. Importantly, we still opportunities to add significant additional acreage in these plays. We planned to request Board authorization for an additional $100 million increase in our land budget raising the total land acquisition budget to $178 million for 2008.

This is consistent with the tremendous opportunity as of today for independents to relating the charge in shale resources plays throughout the United States. Continental has obviously been a pioneer and innovator in recognizing productive potential of these plays, and in most cases, we're getting ready to established a strong acreage position. We were an early adopter and avocation of horizontal drilling and advanced compression technologies that are critical to expand reporting [ph] resources shale.

In the Bakken, we've expanded the use of state-the-art, multistage mechanically diverted frac techniques. These have had a significant impact on the productivity of wells drilled in 2008 versus those completed only a year ago. In the Arkoma Woodford, our simultaneous multistage frac treatments appeared to be generating much better results than the previous single well frac stimulations. In addition to the Continental number one of acreage position in the Bakken, we'll establish a strong position in the Arkoma Woodford, the Anadarko Woodford, the Atoka and Western Oklahoma and the Texas Panhandle and the Marcellus, Rhinestreet and Huron shales in Appalachians. We also have a proven presence in the Haynesville Shale play in Louisiana and East Texas.

Continental of late is expanding this scope of shale resource plays. We have redirected our Bakken drilling program to target primarily the Three Forks/Sanish formation, which we'll believe will be significantly incremental to the Bakken play. Most wells today in this play have been completed in higher and middle Bakken formation. Along with the two TFS wells that we have announced, we have drilled seven additional Three Forks/Sanish wells to total depth and expect to have production results on those wells over the next few weeks.

Both in revenues and earnings continues to strengthen in our outlook, additional growth is very positive. We expect the strong rapid production through the second half driven by the deployment of additional operated rigs. We will continue to build our acreage position where we see strong potential for good returns.

At this point, before I turn the call over to Jack, I'd like thank Mark Monroe for key management role. He's played at Continental the last three years, as President and Chief Operating Officer. We looked Mark at retirement late 2005; wanted to capitalize on his experience like the both credit companies. We relied on his experience and leadership, as we prepared and then launched for IPO last year, last year through a transition from private to public company. Now having accomplished goals we have set, Mark is retiring to spend more time with friends and family as black house [ph] and in the Texas Hill Country and we wish him the best.

Although, he will no longer be a full time member of management at Continental, we will continue to rely on his counsel as a full time Board member. Jeff Hume will step up the role of Chief Operating Officer. And so we move forward with a strong proven management team.

And with that I will turn the call over to another key member of our management team Jack Stark, our senior VP of Exploration. Jack.

Jack Stark - Senior Vice President of Exploration

Thank you, Harold. And Good morning everyone. I appreciate your interest in our second quarter results. I'll start out with a couple of brief comments regarding our Red River units.

We continue to drill infield wells for four rigs and are implementing the plan we announced last quarter to accelerate production by expanding the water injection capacity in the Cedar Hills units. As you may recall, we increased the capital budget by $17 million earlier in this year to implement this expansion, which is expected to do increase peak production for the Red River units from 19,000 net barrels equivalent per day to 21,000 net equivalent barrels per day in mid 2009.

During the second quarter, it was determined that two additional water source wells are necessary to achieve the required injection rates, which in turn will delay reaching the peak production rate of 21,000 net barrels equivalent per day until late 2009. It will happen in the Dakota as the late winter storm struck the first week of May; cutting power to significant parts of the South Dakota units from most of month. As a result, production from the units in other South Dakota wells that we include in our other Rockies category, was reduced by approximately 500 barrels equivalent per day for the quarter.

Moving to our and North Dakota Montana Bakken play, I am pleased to announce we made significant progress on several fronts during... in the play during the second quarter. We grew our acreage position to approximately 525,000 net acres and we remain the largest leasehold owner in the play. We also identified and plan to close on another 36,000 net acres in North Dakota during the third quarter. We had a two operator rigs and remained most active operator in play with 15 rigs total; this includes twelve rigs operated by Continental and three operated by Conoco-Philips our AMI partner.

Net completions were up 56% over the first quarter of 2008, reflecting the growing rig count that we have. To the second quarter completions were exceptional Three Forks producers as Harold mentioned. We continue to see improved results through better completion technology and have begun testing the merits of 10 to 12-stage fracs per well, instead of our typical 8 to 9-stage cracks. And going forward we've planed at four rigs to the play during the second half of 2008, bringing our total rig count to 19 going into the next year. This would include 16 operated by Continental and three operated Conoco-Phillips. We expect to of these rigs to begin drilling in next 30 days.

In the Montana Bakken, we continue to have success with the 320-acre infield and 640 trilateral drilling, supporting the potential for significant unbuilt reserve potential on our HVP [ph] acreage and our 79,000 net acres went to that leasehold.

Since beginning of the tri-lateral and infield drilling program in late 2006, we have drilled 17 gross, 13 net tri-lateral wells and 8 gross 6 net, 320-acre infield wells with average 7-day initial rates of 365 barrels equivalent per day and 395 barrels equivalent a day, respectively. We currently have three rigs drilling in the Montana Bakken and expect to maintain that rig count for the foreseeable future.

As you may have noticed in the press release, production in the Montana Bakken was down approximately 5% in the first quarter '08. This reflects to combination of lower rig count, normal production declines and occasional interruptions in production from shutting wells in while adjacent field wells are being stimulated.

To the increase ultimate recovery of oil from the reservoir, we are planning those CO2 open pumps and water injection pilot ER projects. We're currently in a design to modeling stages and have applied for a grant from the DoE for these projects. But no, we plan to drill our first Three Forks/Sanish test in the Northwest portion of undeveloped Montana acreage block in the early fourth quarter. We suspect the Three Forks/Sanish will prove to be a more effective reservoir than a traditional middle Bakken in this area.

In North Dakota, our second quarter drilling and completion activity increased significantly over the first quarter 2008 and is expected to increase throughout the year as we add up to four rigs North Dakota by year end. During the second quarter, we completed 33 gross, 8.7 net wells as compared to 13 gross, 3.7 net wells, completed during the first quarter, an increase of 135% on a net-well basis.

Initial production rates in our second quarter, of North Dakota Bakken wells also improved averaging 513 barrels equivalent per day, up 13% over the average first quarter of 2008 initial rates of 455 barrels equivalent per day. Usually these improved results directly reflect moving to single lateral wells, multistage mechanically diverted fracs, utilizing open-hole liners in well packers. As a result, we have increased the average estimated ultimate recoveries in our economic model from 315,000 barrels equivalent per well to 400,000 barrels equivalent per well, on a gross basis.

During the quarter, we completed Two, Three Forks/Sanish wells, the Bice 1-29, in which we have 44% working interest and the Mathistad 1-35, in which we have 40% working interest. As previously reported the Mathistad produced an average rate of 1095 barrels equivalent per day during the first five days. But to be consistent with our typical reporting, the Mathistad 7-day average IP was actually 1260 barrels equivalent per day and during its first 20 days online, the Mathistad produced an impressive total of 17,700 barrels of oil equivalent.

Because of these encouraging results and the potential for the Three Forks/Sanish to add significant incremental reserves to the play. As Harold mentioned, we have adjusted the drilling target for most of our recent wells in North Dakota to the Three Forks/Sanish. We currently have seven gross, three nets, Three Forks/Sanish wells in various stages of completion. And nine gross 3.4 net wells... Three Forks/Sanish wells that are drilling.

In other Rocket activity, we've drilled two verticals wells on our East Lustre project in Roosevelt County, Montana targeting three redefined Lodgepole reefs. And as predicted, we did penetrate Lodgepole risk, but the rock was tight and these wells were ploughed. We have no plans to drill additional wells in this project at this time.

In our Haley Red river project, we completed two gross 1.8 net force on our Red River wells, during the second quarter as part of 13-5H and the Merle Johnson 11-4H. Results for these wells so far have been disappointing with higher than expected water cuts, but we believe the water production is related to fall some fracture zones and kind of log drilling in our designing plans to increase oil production by isolating the suspected water production... producing zones from the well board.

We remain optimistic regarding the potential of the play and are currently shedding 95 square miles of 3D seismic to make to further evaluate our acreage. We are preparing to build our... to test our third Haley Red River well this year, the Povchesky 1-1 [ph] and are drilling a fourth well to build more grants [ph] at this time.

In Richland County, Montana we had a significant vertical Red River discovery on our Montana Bakken acreage. The Smart 123 [ph] in which were 89% working interest floated a seven day average initial rate of 442 barrels of oil equivalent per day from 32 feet of perforations in the Red River D Zone. This is the second successful vertical Red River well drilled on our 33 square mile typical 3D survey, utilizing proprietary processing and interpretation techniques. Our first well the year ago 19 [ph] was completed last year. We are very encouraged by the technical and economic success of these two wells and it demonstrates the potential that exists from conventional reservoirs underlying our Bakken acreage in Montana, North Dakota.

To further identify these Red River opportunities under our 153,000 net acres in Montana Bakken, we have a licensed, reprocessed then interpreted a total of 88 square miles of 3D data and have another 120 square miles of data being processed. To-date we have identified 19 gross, 11 net prospective Red River locations and are drilling the first of the four locations we plan to drill in the second half for the year.

Moving on to the mid-continent, the drilling program on our 46,000 net acres in the Arkoma Woodford continues to provide good results. During the second quarter, we completed 18 gross, 3.3 net wells. We continue to see efficiencies in our operations, particularly with regard to drilling days which are consistently averaging around 30 days per bud, which is 40% below the last year. Of note are the results of our recent two well simul-frac of the Ireland 215 and Ireland 315 wells in our Ashland project. These two-wells float at 7-day average initial rates of 6.2 and 7.2 million cubic feet per day respectively. The wells were drilled parallel to each other approximately 1320 feet apart, 4400 feet in length and were stimulated with 9 stage fracs. The nearby Ireland 415 was fracture stimulated immediately following the Ireland 215 and 315 and slowed at an average 7-day initial rate of 1.7 million cubic feet per day.

We had 21% working interest in each of these wells. We believe by fracking the well simultaneously or near simultaneously we are more effectively fracturing a rock due to better pressure consignment. We adjusted our drilling schedule to accommodate simul-fracking as often as possible and there are several planned in the third quarter.

We've recently completed shooting 18 square miles of proprietary 3D data, in our Salt Creek project and expect processing to be completed by late August. To cost effectively expand this 3D coverage in Salt Creek, we also licensed in additional 8 square miles of non-proprietary data. Combined this data, we used to evaluate and guide future development of the Salt Creek area. Then to guide development of our East McAlester project, we are in a process of acquiring 55 square miles of 3D data as part of our larger group shoot. We expect delivery of this data in the late fourth quarter or really first quarter next year. We currently have five rigs drilling in the Arkoma Woodford and plan to add up to two additional rigs in the play, the first in August and the second probably in October.

Moving, in second quarter we reported that the Marriott 1-18, located in Blaine County, Okalahoma produced at a 7-day average initial rate of 2.5 million cubic feet per day and 45 barrels per day from the Springer wood sand. We had another significant discovery during the second quarter in our Wolsey 2-9, also located in Blaine County. The Wolsey 2-9 completed flowing at a 7-day average initial rate of 5.6 million a day and a 142 barrels account received from the Springer Cunningham sand. We have 85% working interest in this well. Both wells are unstimulated natural completions and appear to be outstanding producers.

In our Michigan Trenton/Black River, project we drilled two gross 1.7 net wells during the second quarter. Both were producers including the Boardman 1-1and the Wessel 2-6A. The Boardman 1-1 is currently flowing at 150 barrels a day under state restricted test rates and will increase to 200 barrels per day and really August is part of the testing process.

The Wessel 2-6A is also undergoing state testing, and is currently flowing 110 barrels of oil per day under state restricted rates. We expect to increase the test rates to 150 barrels a day and 200 per barrels per day in the next 30 to 60 days if gas oil ratios warrant.

To-date we have drilled 10 gross 6.8 net Trenton/Black River wells with nine producers and one well temporarily abandoned. Five of the producers are capable of producing in access of states restricted reliable rates of 110 barrels a day. The state has conducted hearings to consider increasing their levels with these wells and we expect to have ruling from the state in early October. The Trenton/Black River is a 3D seismic driven play and we currently have seismic coverage of approximately 15% of our 48,000 net acres.

We will complete acquisition of another 20 square miles in our Chicago and Ohio [ph] 3D shoot by mid August and expect to acquire another 5 square miles on our Dog Lake project later in the year. Although it's difficult to predict just how many opportunities will be identified on the new data, it seems reasonable to expect that we will commence a multi-well drilling program, during the fourth quarter this year.

In other emerging shale plays, as you knowledge, we are one of the more active resource players in the industry and we have leasing efforts ongoing in several emerging plays. And have begun or will begin drilling on this acreage before year end. In the rapidly expanding Haynesville shale play, we'll now control approximately 17,000 net acres in the Northern Louisiana area and continue to add acreage to our position. We expect to spud our first well in the fourth quarter. In the Anadarko Basin in Western Okalahoma, we now control approximately 94,000 net acres that we consider as prospective for the Woodford and plan to spud our first tracery towards test in August.

We also own approximately 32,000 net acres in the Atoka fair away and are drilling our first horizontal test this time. A pilot hole was drilled in course of the Atoka were taken for further evaluation of the reservoir. And in the Appalachians, we now own 88,000 net acres in the Lower Huron, Rhinestreet Marcellus plays and continue to build on our position. The bulk for this acreage is located West Virginia, Ohio, and New York where the shales have at found debts of 1000 to 5400 feet. We're currently drilling our first-four wells targeting Rhinestreet, then Lower Huron shales in Southeast, Ohio.

And with that, I'll turn it back to Harold.

Harold G. Hamm - Chairman and Chief Executive Officer

And we are ready for Q&A now?

J. Warren Henry - Vice President of Investor Relations

Yes we are ready for Q&A sir. Eric?

Question And Answer

Operator

[Operator Instructions]. Your first question comes from the line of Tom Covington with Broadpoint Capital. Please proceed.

Thomas E. Covington - Broadpoint Capital

Thank you. And good morning everybody.

Harold G. Hamm - Chairman and Chief Executive Officer

Good morning.

J. Warren Henry - Vice President of Investor Relations

Good morning.

Thomas E. Covington - Broadpoint Capital

Question on the... in terms of that you are adding incremental five rigs by year end. What do you think that's going to do to the sort of drilling budget as we go forward, in terms of I know you talked about the leasing budget going up $100 million. What do you the drilling budget is going do by year end.

Mark E. Monroe - President and Chief Operating Officer

Yes Tom, this is Mark. If you kind of look at the guidance that we've put out there in and going to use commodity prices for the first six-seven months actual versus kind of where they are, presently I think you'll see cash flow to be about $1 billion. We've got a budget of 7.83; we'll go to Board today for another $100 million on acreage. So that's 8.83 or less about $120 million, we could fund out of cash flow in additional drilling.

At this point in time, we don't have a number that we are going to the Board. As you knowledge, we are adding only five rigs, but only towards the second half for the year. So I mean you are looking at maybe two incremental rig years if you will. So I think that it will be in 10% to 15%. But that's just a guess at this point in time, in terms of when we are going to the Board for additional drilling.

Thomas E. Covington - Broadpoint Capital

Okay. In terms of the... there is obviously been some additional water injection being there water source wells being drilled in the Red River which is slowing a little bit of the ramp there. Do you think the additional drilling will offset that, and you will still be able to make your sort of 40,000 to 43,000 barrel of oil equivalent year-end exit rate in 2008?

Harold G. Hamm - Chairman and Chief Executive Officer

Yes Tom, we've been a lot good. We've come very close to offsetting that. We think that actually the ramp up in this water injection is going to happen in late August-September, at a point that we sure recover most of that. So we are not altering our 43,000 barrel projection at this time.

Thomas E. Covington - Broadpoint Capital

In the Sanish as you look at the well costs. Give me a sense what the well costs are and how you expect those to evolve, as you move to more frac stages going forward?

Mark E. Monroe - President and Chief Operating Officer

Yes Tom its Mark again. The average cost right now that we're looking at in kind of Rocket Galaxy area, which is little bit deeper in our North Sea area which is little a bit shower is about... now about $5.8 million. And that's a combination we've taken that up probably from about five earlier this year that we think have in our economic model. And that's a combination of doing a few more stages, little bit bigger frac jobs we're going to this high strengths ceramic components which have added little bit of cost to it. As you know steel has gone up little bit. But that 5.8 is a good number whether you are really thinking middle Bakken or whether you are thinking Sanish because as you know, there is maybe on an average 75 feet of difference. So it really doesn't change the cost.

Thomas E. Covington - Broadpoint Capital

As you look at where you are drilling. My sense is you are sort of keeping original drilling schedule and serve just drilling Sanish for as opposed to Bakken wells now. Is that the case or are you testing different areas for the Sanish, as you sort of look at the new reservoir?

Jack Stark - Senior Vice President of Exploration

No that is the case. We are testing the Three Fork/Sanish basically from our Rocket project on up to our Norse project. And that you are correct in saying that we just modified drilling middle Bakken wells turned down to just drilling Three Fork/Sanish wells.

Thomas E. Covington - Broadpoint Capital

And one last question. In the 88,000 acres in the Appalachia, how much of that is in sort of a high pressure Marcellus areas Western Pennsylvania and Northern West Virginia?

Jack Stark - Senior Vice President of Exploration

We don't have that much. It's in what is considered the high pressure, slightly over pressured Marcellus in Pennsylvania. The bulk of it is up in New York and down South of that area just in West Virginia and New Southeast Ohio. So we are at North and in New York we expect to be normally pressured some of this down in West Virginia and Ohio can be slightly under pressure.

Thomas E. Covington - Broadpoint Capital

Thank you very much.

J. Warren Henry - Vice President of Investor Relations

Thank you, Tom.

Operator

Next question comes from the line of Subash Chandra with Jefferies. Please proceed.

Subash Chandra - Jefferies & Co

Yes, hi, Good morning. First question is... the June average of 33 versus the Q2 average of 31 change. Where is the delta there?

Jack Stark - Senior Vice President of Exploration

North Dakota, it's been a growth area as the Arkoma Woodford is, as you would expect. I mean those two areas really the growth. And as proceeded through the second quarter, and of course where we expect to see the growth is, as we look forward into third quarter and fourth as well.

Subash Chandra - Jefferies & Co

Okay. In the Red River I guess, the way I understand it is that the issues were pretty much all on the water side and the availability of water side not perhaps the amount of water required to get to you the 21,000. So I guess that the gist of it is that the simulation studies or whatever sort of studies you've done to get 21. Those inputs and outputs have not changed and it's just been the amount up or I should say the source of water that's been the issue here?

Harold G. Hamm - Chairman and Chief Executive Officer

Right. We've taken a lot of water out of the Lodgepole and we just started to running short. It's good thing that the team of have recommended we up those volumes, and that allowed us to find out how much water we had. So round up, we just had to drill couple of wells and one of those being drilled and we've drilled that and back-to-back with it so we don't expect very much delay, it set us back around that, its not...

Subash Chandra - Jefferies & Co

Tempered.

Mark E. Monroe - President and Chief Operating Officer

As you recall Subash, we announced $17 million increase in our budget last quarter to the Heels field to expand the water injection. We thought that we might have the capacity with existing water source wells and turned out as Harold said that we didn't and... just shifted the curve a few months is really all its done.

Subash Chandra - Jefferies & Co

Right. Sure. No, not enough for water versus, not enough oil. I'll take the former.

Mark E. Monroe - President and Chief Operating Officer

Exactly. And it's not that we can fix the former.

Subash Chandra - Jefferies & Co

Okay. Alright. In... the Hulton process [ph] I guess EOG is doing something to North Dakota on that. What do you sort of seeing maybe evolution here, do think there is a chance to go from primary to share recovery out there and what are the limits or Hulton process [ph] program, I guess, A) the CO2 is something that's trucked in and really what sort of response time are you looking at on one pilot for instances?

Harold G. Hamm - Chairman and Chief Executive Officer

What I see is the truck and rail enter the site and as far as the time... I think that's more or less a primarily a test. We're at the process itself and that's where we hope to tying with that open path.

Mark E. Monroe - President and Chief Operating Officer

And there is also the trucking and the railing, obviously just be doing to pilot phase and we've talked to a coal gasification plant operator recently and there is quite a bit of coal as you know in that area and one of the problems really in creating more coal gasification or electricity plants is what you do with the CO2 there and we would look to be a source for them to dispose off the CO2. So, but the first thing to do as Harold mentioned is to get pilot running and as Jack mentioned to you we are in the design stage, in the modeling stage and have applied for a DoE grant, so we look forward to moving that process forward and get the test in Montana.

Subash Chandra - Jefferies & Co

Do you think the normal evolution though is intact of primary to maybe of water flood?

Mark E. Monroe - President and Chief Operating Officer

Well that's the... really to propensity of this test is to see what water is going to be cheaper and more accessible but it maybe that going directly to CO2 is the best approach.

Subash Chandra - Jefferies & Co

Okay and one last one from me. Any more color on the Bice well and that you sort of have an ability to discern whether it's a distinct reservoir, you've mentioned the gas oil ratio is different. But a commentary maybe on the ability to discern that this is a distinct reservoir you're draining. And second how volume might have held up in the Bice well?

Mark E. Monroe - President and Chief Operating Officer

Volumes have held up well. I guess that most encouraging thing to us as far as separate reservoir is volumes that we're seeing on some of these well. That Mathistad was a awfully strong well, out there and we can send to see good volumes coming out of that Three Forks/Sanish. So, I think it's little bit too early as far as gas-oil ratio information at this time, which we have sent more concrete to give you on that. But at this point, we don't.

Subash Chandra - Jefferies & Co

Got it. Thank you.

Operator

Your next question comes from the line of Joseph Allman with JP Morgan. Please proceed.

Joseph Allman - JP Morgan

Hey, good morning everybody.

Harold G. Hamm - Chairman and Chief Executive Officer

Hey, Joe, good morning.

Joseph Allman - JP Morgan

In the Three Forks/Sanish play, any incremental well results. I know you must have a couple down and completed at this point?

Jack Stark - Senior Vice President of Exploration

Actually we've got two that we are completing at this point and we've got five that are awaiting on frac jobs. So we've got two that are testing and just don't have enough results on if we did we put it out in the press release. And our plans are to, at some of point in time when we get some more data points probably be look at doing something may be in late August, maybe it will be in September once you get enough data points to put out into the press release and go through our results. We'll have a good slate of really from our southern end of Rocket Galaxy to Norse will have a few test probably in each area to talk about.

Joseph Allman - JP Morgan

Okay that's helpful, thanks. And then in terms of the development of the middle Bakken what will you increase in the rig count, will that help you to still to focus a lot on Three Fork/Sanish and also develop the middle Bakken simultaneously, or do you think it must be after at this point. And for the foreseeable future it will be for Three Fork/Sanish?

Mark E. Monroe - President and Chief Operating Officer

Well, we addressed our target based on the areas, I mean down south in our Normandy project there we'd focus more on the middle Bakken. And if there is any particular area up there, I mean there are some areas with middle Bakken, I mean it's still a great target. And, so where we feel we have upside or a better opportunity in the middle, we are going to go for there, so we will target the best opportunities.

Jack Stark - Senior Vice President of Exploration

But obviously Joe, we got so many separate 1280s to drill. I don't think you will see us doing much drilling where we are putting one middle Bakken and one Three Fork/Sanish in the same unit, see much of that here in the next year, just because we got so much to do to cover our acreage.

Joseph Allman - JP Morgan

Got you. Any lease expiration issues at all to deal with?

Mark E. Monroe - President and Chief Operating Officer

We've been leasing out there since 2003. So it's been a process of covering leases expiring renewing some. We've got options from some to renews. So it's like everybody out there. You are protecting your acreage whether you do it by putting it a drill bit in the ground or by renewing it. The difficulty in there is, you drill it. So it's something everybody who is the play, who's been in the play for a while as manages. And we haven't had any problems with protecting acreage that we need to. And we look far enough to end it hear, nine months ahead to make sure that we are going to get something renewed or elsewhere we'll drill it.

Joseph Allman - JP Morgan

Okay good. And then the additional acreage you've acquired in the Bakken including the 36,000 that you had a closed on in the third quarter. Can you talk about the locations of that acreage?

Jack Stark - Senior Vice President of Exploration

Yes the locations of the acreage that we've acquired in North Dakota Bakken you will cover that Harold.

Harold G. Hamm - Chairman and Chief Executive Officer

Yeah its... over on the Eastern side and John our hidden prospect [ph] which we've been very high on that area.

Joseph Allman - JP Morgan

So can it be the sort of the South eastern part of the.. if you look at the place order?

Harold G. Hamm - Chairman and Chief Executive Officer

Yes.

Joseph Allman - JP Morgan

That's okay. And we going some retail results on that far west side in North Dakota, an area where previously didn't look very economic. Does that side of the basin interest you and is that something you think might be prospective for the middle Bakken and over the Three Fork/Sanish?

Jack Stark - Senior Vice President of Exploration

Obviously there Joe, it's very good to ask to, it's just to ask the new technology versus [ph] as it acquires to North Dakota and excite everybody and everybody taking a relook at that entire area.

Mark E. Monroe - President and Chief Operating Officer

And we do have some acreage off the western side of the Nesson as well. And that's an area we continue to look at. And we've talked about the possibility of the Bakken having much wider potential throughout the base, most the acreage has been... is focused on the Nesson in the east and this starts validating the possibility to moving the west of the line and on up into the Northwestern part of basin.

Joseph Allman - JP Morgan

Got you. Then just to cover quickly, on the cost and I know you talked about the Bakken wells going from kind of 5 to 5.8. What do you see kind of going forward? Do you see the ability to kind of increase efficiencies and reduce that costs. And then could you also kind of cover the costs and I guess more importantly is the Three Fork/Sanish really and then also the Arkoma.

Mark E. Monroe - President and Chief Operating Officer

I'll just take the last one first. The Arkoma Woodford actually, we've seen a reduction in cost of that this year. We are now at about $4.1 million in our latest IPs in that comparison just over 4.2. At the beginning of the year and that's being driven by, as you pointed out drilling efficiencies. We've achieved those to a great degree in the Woodford and we're doing as many of you follow, we were doing more power drilling simul-fracs. We're not drilling in one location for two-wells and that's saving some costs and obviously rig moves and so forth.

And drilling on 1280 obviously, we can't do that sort of stuff in North Dakota. But I think there is some possibility of some drilling efficiencies. I mean we're seem to be cutting times a bit there in North Dakota. We don't see... obviously we're seeing a lot pressure on steel prices, it's hard to forecast what we'll see over the next six months. Rig costs I think have... there's been a little pressure on rig cost instead of 17 to 19 or probably 19 to 20 not a big move, but there's been a little pressure there. We don't expect to see a big movement in our cost, hope to enjoy some efficiencies, and more efficiencies in North Dakota as we've enjoyed in the Woodford.

Joseph Allman - JP Morgan

Helpful and then those three wells you mentioned that were Montana Bakken wells, the ones you listed in the release. Could you identify which of those were infield wells and which one are tri-laterals?

Jack Stark - Senior Vice President of Exploration

Sure.

Joseph Allman - JP Morgan

Like LeaJoe and there's one side and there content.

Jack Stark - Senior Vice President of Exploration

We... as far as the... I was going to say your question was that are these, which ones were infield?

Joseph Allman - JP Morgan

Yes, which ones are --

Jack Stark - Senior Vice President of Exploration

We had the Mylar, the Constance and the Swenseid were 320, infield wells and those wells completed for 7-day averages in the range of 235 to 336 of barrels equivalent per day and as far as trilateral are concerned this list have got here is in sort high date very effectively here but I think that I'm looking forward at the... I guess the Pelican is the one that we did complete in the quarter there and we'll get 228 barrels equivalent per day on that well.

Joseph Allman - JP Morgan

And that LeaJoe or --

Jack Stark - Senior Vice President of Exploration

Then also we completed the Cherion [ph] no that would be Swenseid, that's a trilateral.

Joseph Allman - JP Morgan

Okay, that LeaJoe, that's in releases in trilateral infield.

Jack Stark - Senior Vice President of Exploration

The LeaJoe, I'm sorry... yes it is a 320 basically it's drilled on what's the super unit out there. It was where there are some correction sections and it was drilled to some inner unit well and made a very nice completion of there 609 barrels equivalent per day.

Joseph Allman - JP Morgan

Okay, great. Very helpful. Thanks guys.

J. Warren Henry - Vice President of Investor Relations

Thank you, Joe.

Operator

Your next question comes from the line of Sunil Jagwani with Catapult. Please proceed.

Sunil Jagwani - Catapult

Hi, good morning. I just wanted to enquire about the acreage in the Marcellus area. What has your team determined to be some of the key variables that is determining, I guess your leasing activity. I think you mentioned depths as one of the key factors you were looking at earlier in the call, but if you can clarify how you're looking at the play both the Marcellus and Eureka please? Thank you.

Jack Stark - Senior Vice President of Exploration

Well we're really are; we have some proprietary things that we look for in these plays so a lot of it's based on some traditional offset drilling activity, historical results out in the year end and thickness debt is ruling out of factor appointed that out just demonstrate approximately will add relative to other parts of the play when you're down in Pennsylvania, you're down some loose ratio, down around 7000, 7500 foot range, and so that was the reason that I pointed out depth.

Sunil Jagwani - Catapult

Okay. And this question I guess applies to all of your recent acreage leasing activity because you mentioned in the press release, a good amount of acres that were added in the quarter including the Haynesville. Just ballpark, we obviously see all this press about sharply higher acreage prices. Is that what you're seeing and is that what we should assume you deployed to acquire this acreage?

Harold G. Hamm - Chairman and Chief Executive Officer

I think you're seeing higher acreage process in all these plays, workers get in the act of the what I call, creating land grab is going on with acreage in these reservoirs plays across U.S. So you're seeing higher acreage prices for sure. But there is still opportunity, as I stated earlier in these resource plays picking up the acreage on the ground and that's what we do. And it's been very successful for us and we identify where we want to be and go after on the ground with land crews and it has been very successful as far as we are concern in doing this.

Mark E. Monroe - President and Chief Operating Officer

There is the lot of difference between what you read in the press I suppose, when someone makes an acquisition in terms of with the land cost is as compared to what Harold just said in terms of what you can do if you are on the ground knocking on the land owner's door and negotiating something there.

Sunil Jagwani - Catapult

So, I mean given that statement should we assume that down the road if the opportunity were to present itself to consolidate acreage in the Bakken, would you not ever consider a corporate deal?

Mark E. Monroe - President and Chief Operating Officer

Oh Sure we would. Absolutely I mean if it was a reasonable price and if it fit us well strategically, obviously the Bakken is that sort of element, sure.

Sunil Jagwani - Catapult

Alright, thank you.

Operator

Your next question comes from the line of John Freeman with Raymond James. Please proceed.

John Freeman - Raymond James

High guys.

Harold G. Hamm - Chairman and Chief Executive Officer

Hi John.

John Freeman - Raymond James

First question just to start up again on your Three Fork/Sanish, I understand it will be allowed to... if it's a separate reservoir. What do have the Petrohawk well is going on line for about 21 months. Just... what have you learned from just looking at the monthly production history on that well?

Jack Stark - Senior Vice President of Exploration

It's a great well. And then keep in mind that's a natural collision.

John Freeman - Raymond James

Right.

Jack Stark - Senior Vice President of Exploration

It's not stimulated. So, it's got some extremely well enhanced fracture permeability there tied into reservoir. And it is basically on a projection of the Antelope field which was an I think it was a 50s vintage field discovery and developed as vertical wells pretty effectively even back then, with due to the fraction related to that structure.

Mark E. Monroe - President and Chief Operating Officer

Yes my guess John, is it is seeing contribution for both the middle Bakken and Sanish just because it's so busted up there that probably, have that well bore been placed in middle Bakken it probably would have been somewhat similar well. I mean it's just... it's seeing contribution from both reservoirs, I would imagine given --

Harold G. Hamm - Chairman and Chief Executive Officer

Yes, this type of fracturing I believe is something it's more of a macro tectonic-type movement where you have actually busted a rock from top to bottom and so I think, Mark is right, that it is likely that you are communicating all the Bakken itself in the surrounding reservoirs.

Mark E. Monroe - President and Chief Operating Officer

And then that maybe... that may explained some of partials productivity to, I mean we've seen the core down there that demonstrated some very significant vertical fracturing and then the reason their wells maybe a little bit better, they may well be seeing contribution from both the middle Bakken and the Three Forks/Sanish.

John Freeman - Raymond James

Thanks. Moving to the Woodford shale. The last two simul-frac wells have completed in that area. Is it the same areas that previous four simul-frac wells went out last quarter. And if so, is there any thing being done differently on this last couple of that would have accounted for much better results on these last two simul-fracs versus the first four?

Mark E. Monroe - President and Chief Operating Officer

Completed in the similar area; I don't know if that we could point to anything exactly. I think maybe the laterals maybe have been a little bit longer here do you recall. Jack.

Jack Stark - Senior Vice President of Exploration

I can't recall for sure Mark on that, but I do. You are in a similar area here but from location to location you will see a change in outcome. And that's going to be tied to not just the completion, but also the geology.

Mark E. Monroe - President and Chief Operating Officer

I think a lot... our teams are trying to get every foot they can with each facing in it and there we are drilling lot of this outsiders, had outside in the space where we come in zone and basically maximize footage length. And no doubt we are getting better these the state fracs. The teams have improved in their ability to get these done a lot better. So I think that's probably that much of it is anytime in my opinion.

Sunil Jagwani - Catapult

And then just moving on to the Trenton/Black River on the seismic that you have accumulated so far. How many locations have you identified on the seismic that you have accumulated?

Jack Stark - Senior Vice President of Exploration

I think we have maybe, maybe as many as 12 on the two shoots that we had and at this point in time, we drill as we said ten wells, we may have another target or two depending on lab that we want to take, on the shoots we've done. But most of the activities are going to be on future shoots and of course we'll have our 20 square mile interpreted by mid-August we expect and as you see on our map that's going to the heart of the Trenton/Black River trend there and an area that it looks like they may have lost the way few times. And so we're hopeful that we'll see several good opportunities there.

Sunil Jagwani - Catapult

Okay and then last question I had just on the Haynesville. What parts [ph] in Louisiana is your acreage located in the Haynesville?

Mark E. Monroe - President and Chief Operating Officer

Jack has given me... he's giving me the no say sign here.

Sunil Jagwani - Catapult

It was worth asking. Thanks guys.

Mark E. Monroe - President and Chief Operating Officer

Yes. Good try.

Operator

Your next question comes from the line of Eric Hagen with Merrill Lynch. Please proceed.

Eric Hagen - Merrill Lynch

Hi, good morning. Follow up on Trenton/Black River; what's your total production out of the play now and also how might that be impacted if you get the increased volumes?

Harold G. Hamm - Chairman and Chief Executive Officer

I think there is volume increased that we'd hope for would be 500 barrels a day. We're looking for ruling back from the straight, I think the mid August. That would be hopeful for volume. So right now that got us down to 100 to 200 on the wells injects at capable 5 or 6 wells. So that's kind easily to take you there.

Mark E. Monroe - President and Chief Operating Officer

I mean, during testing times, we can get up to maybe 300 barrels a day but ultimately unless we get approval from the state, we've got to ratchet those back to 110 barrels per day and we were to get up to 500 obviously that's a significant increase in the amount of production that we could enjoy at these wells.

Eric Hagen - Merrill Lynch

See if 10 completed 9... I'm sorry 10 drilled, 9 completed and potentially on those 9, you can get up to 500 barrels per day proved well and what's your net revenue interest on those wells.

Mark E. Monroe - President and Chief Operating Officer

Could be about, we are at 83 working. So about, I'll call it 65%, 66% net revenue. And not all those wells as Jack were saying five of those wells, we feel very comfortable, can make quite a bit more than the state amount but four remaining we've got a mixture of wells that on a average would be less than the 110.

Jack Stark - Senior Vice President of Exploration

We have that couple wells that Jordan's operator, we have 50% interest in one of those it's a smaller oil well. I think it was kind of 25 barrels a day and the other was primarily gas. So you take those two out of that equation, then we have another wells that just not capable.

Jack Stark - Senior Vice President of Exploration

Eric, let us say Warren, will get back to you this morning with sort of the details on the wells and which ones... what are in our eyes on and what the impact might be on a net basis if we were to get up to 500.

Eric Hagen - Merrill Lynch

Okay, great. And then in the Sanish probably two premature, but in terms of any idea or range of what you might pickup incrementally over the Bakken which as you said is about 400,000 barrels.

Jack Stark - Senior Vice President of Exploration

It is way too early. I mean all we've got is to operate a test at this point in times. So its just hard to say, we're not, we're really not claiming that the Sanish, at this point of time is going to be... we think it's got a picture to be better than middle Bakken, but at this point in time, we don't know and I don't know that we would claim at this point in time that it will be above 400,000 that we're modeling for the middle Bakken. We just need some more data to be able to say something like that.

Eric Hagen - Merrill Lynch

Great. Then last one was just for Harold. Any comment on commodity prices, oil in particular. And also on the idea that the market will be swamped with gas, next year from the shale plays Marcellus Hayneville?

Harold G. Hamm - Chairman and Chief Executive Officer

You see some of these plays are atop of that gas first of all. You'll see some of these plays that come on somewhat slower. And Marcellus is going to be one of those that takes I think quite a bit slower then some of the others, basically it's due to infrastructure. Lot of needs out there for better infrastructure pipes and rigs and services and you name it. So I think that will... that's going to come up slower than some of the rest of them. And Hayneville we are seeing some opposite rates going out there. But even that play is going to, probably heat up a lot slower as far as supply coming to market. That's going to have its own challenges, pressure gas, tectonic area, under pressure systems and et cetera. So I wouldn't think next year is going to be about of gas on the market. That would count on that at all.

As far as crude oil; we've just not seen anything change in fundamentals. We've seen demand slacken a little bit in the U.S. but rest of world we've not seen that slackening happen. So the fundamentals of being short with little bit transportation fuels remains. So as far as crude oil gain offer cheap in the next foreseeable future, I'd still see that happening.

I think as we go forward its going to become even more critical in 2009 and beyond. So we... I'd kind of stay at settling down to a range maybe $120 to $135 range. And that's good, I don't think the country is ready to $200 oil. And I think it would be devastating to see that. So obviously, we have to change to natural gas as transportation fuel in the future. But there are things, and we will have adequate supply to do that. And the country needs to make that move going forward.

Sunil Jagwani - Catapult

Great. Thanks gentlemen.

Harold G. Hamm - Chairman and Chief Executive Officer

Yes.

Operator

Your next question comes from line of Justin Toy with Toy Brothers [ph]. Please proceed.

Unidentified Analyst

In terms of determining Three Forks separation, you highlighted some volumes earlier. Can you talk a little bit about what you suspect is the scope of the layer or space between Three Forks and the middle Bakken?

Mark E. Monroe - President and Chief Operating Officer

Yes, we have actually have on our website if you go out there and look at our presentation at there, we actually have a map out there that shows the inner role between the bottom of the upper shale and the bottom of the lower shale. So you can get kind of a view, of where that interval is stake as where it goes from maybe 25 feet to 100 feet. Jack would you like to comment?

Jack Stark - Senior Vice President of Exploration

Yes, I mean that's a great source, just because of the map, it pretty well defines the vertical separation between the middle Bakken and Three Fork/Sanish. And the contention here is that, the amount separation here just intuitively indicates or suggests that you would have two separate reservoirs here. But that remains to be seen and that's what we are in the process of doing right now is with our drilling. And it's going to take a while to actually determine if they truly are separated, they are tied, sure it looks like in some areas where you have a high degree of faulting and fracturing that you have a two in communication with each other. I think that was definitely... clear improvement up there on the Antelope field.

And I think that... so that does occur out there. But in those areas we you are less fractured and you are just down with more micro-fracturing or slight cracking of the rock, it's very plausible and very likely to hit on you and you are just not going to drain that Three Forks well up in the middle Bakken. So especially when you are 75 feet above it, above the Three Forks there in some areas.

So from our standpoint about two-thirds of our acreage, there is probably 54 separation between the middle Bakken and the Three Forks, probably and a two-thirds of our acreage. So that's why we are very interested and are very aggressively pursuing evaluating the Three Fork/Sanish with our drilling program by now. We'd like you, would like to know it is just going ahead incremental reservoirs to play in that. So it will be significant.

Unidentified Analyst

And the positive, the significantly higher results on the second well in terms of IT. How much of that versus the first well is related to the placement of the second well, or just sort of more than learning curve and technology applications of the second well?

Harold G. Hamm - Chairman and Chief Executive Officer

I don't think we can answer that. That second well was 23 miles away from the first one, this one we decided to test that area and like Mark said a test is from across a our acreage spread at now so have wells after the test across at acreage spread. So to improve, we can't answer that.

Unidentified Analyst

Okay. Thanks very much.

Harold G. Hamm - Chairman and Chief Executive Officer

Yes.

Operator

Your next question is a follow up question from the line of Subash Chandra with Jefferies. Please proceed.

Subash Chandra - Jefferies & Co

Yes, hi. Just want to clarify something. On the fracture stimulation and the shut ins when you do so up in Montana. It's still 320 optimal or are there areas where that might be too dense?

Jack Stark - Senior Vice President of Exploration

I think 320 is optimal. I mean, I think we determined that 320 works across our acreage. I don't think it's too dense, I mean with higher oil prices, I'm not sure that is not an opportunity to even take it more dense.

Subash Chandra - Jefferies & Co

Thanks for that, I got it. Okay. And the TBR wells, could you remind me again the 10 locations or the 12 locations, what the net amount of acreage that was or gross? What the actual number was for that... the acreage in that seismic shale?

Jack Stark - Senior Vice President of Exploration

How many acres I guess is related to the actual wells that were drilled in there is that what you're saying?

Subash Chandra - Jefferies & Co

Yes, exactly.

Jack Stark - Senior Vice President of Exploration

We've covered about 7,000 acres through seismic so far.

Subash Chandra - Jefferies & Co

Okay, 7000 acres. And is it that big step out that was temporarily abandoned?

Jack Stark - Senior Vice President of Exploration

No, it was within, it was actually an offset to the ... it's our Wessel 1-1 which is essentially an offset to the Haynesville in the same session Haynesville.

Mark E. Monroe - President and Chief Operating Officer

We are talking about the dry hole here? [Multiple Speaker]

Jack Stark - Senior Vice President of Exploration

I was going to say that's a temporarily been and it is the Wessel and really that we're some fracture indications in the well itself and we believed that it was temporarily abandoned just from the standpoint that we're not convinced it's a dry hole and that we could possibly stimulate it or possibly reenter in side tract this well into maybe a more favorable position in these and we're looking to get the results of our Chicago in order to 3D shoot to just further assess the data and the seismic anomaly seen around that Wessel 1-1.

Unidentified Analyst

Got it. And what was the... which was the name of the dry hole?

Mark E. Monroe - President and Chief Operating Officer

No, it's the Wessel, it's an abandoned well.

Jack Stark - Senior Vice President of Exploration

Temporarily abundant. Yes Wessel 1-1.

Unidentified Analyst

Okay. So there hasn't been any confirmed dry holes yet in TBR program?

Mark E. Monroe - President and Chief Operating Officer

No that's only one that we have now made a completion in and we're debating with that we want to do with that as I said.

Unidentified Analyst

Got it. Okay, thank you.

J. Warren Henry - Vice President of Investor Relations

Eric, any other questions?

Operator

And we are currently showing no more audio questions. Thank you.

J. Warren Henry - Vice President of Investor Relations

Then we'll turn it over to Harold for some closing comments.

Harold G. Hamm - Chairman and Chief Executive Officer

In summary, I would just like to enforce few key points of the related strategic outlook. We'd an outstanding first half of 2008 with a strong growth in revenue, cash flow and net income to the extent that we have planned to increase our CapEx budget again for 2008. It's important to note that we plan to exit this year 35 operating drilling rigs. We are continuing to build our acreage, inventory in U.S. shale plays. And we intend to increase our land acquisition budget by another $100 million to take advantage of this opportunity that we see out there. We expect that these efforts will provide strong growth momentum as we move into 2009.

We also look for continued strength in market prices and especially for crude oil as essential input in the manufacture liquid transportation fuels. With this strong lender at back, we are focused on improving our results further and expanding our role as the leading innovator and harvesting shale resource plays. This is an exciting time for Continental and U.S. energy industry in general. And we are focused on building additional shareholder value to a careful execution of our crude oil concentrated growth strategy.

I will thank you everybody again for participating on the call this morning. We are looking forward to reporting additional progress to you again next quarter.

Operator

Thank you for your participation in today's conference. This concludes our presentation. You may now disconnect. And have a good day.

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Source: Continental Resources, Inc. Q2 2008 Earnings Call
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