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Executives

Harold Hamm - Chief Executive Officer

John Hart - Senior Vice President, Chief Financial Officer and Treasurer

Jack Stark - Senior Vice President, Exploration

Gene Carlson - Senior Vice President, Resource Development

Tom Luttrell - Senior Vice President, Land

Rick Muncrief - Senior Vice President, Operations

Jeff Hume - Senior Vice President & Chief Operating Officer

Analysts

John Freeman - Raymond James

Steve Berman - Pritchard Capital Partners

Ronnie Eisenmann - JP Morgan

Subash Chandra - Jefferies & Co

TJ Schultz - RBC Capital

Eric Hagen - Lazard Capital

Andrew Coleman - UBS

Mike Breard - Continental Resources

Continental Resources Inc. (CLR) Q3 2009 Earnings Call November 5, 2009 10:00 AM ET

Operator

Good day ladies and gentlemen, and welcome to the third quarter 2009 Continental Resources earnings conference call. This conference call is being recorded. Today’s call will include projections, assumptions and guidance that are considered forward-looking statements. Actual results will likely differ from those contained in our forward-looking statements. Please refer to the company’s filings with the Securities and Exchange Commission for additional information concerning these statements and risks.

Chairman and CEO, Harold Hamm will begin this morning’s call with an overview of our third quarter achievements and 2010 outlook. He will be followed by President and Chief Operating Officer, Jeff Hume who will provide additional detail on financial and operating results as well 2010 capital spending plans.

Finally in the question-and-answer period, several addition officers will be available to answer your questions; John Hart, Chief Financial Officer; Tom Luttrell, Senior Vice President of Land; Rick Muncrief, Senior Vice President, Operations; and Jack Stark, Senior Vice President, Exploration.

At this point, I will turn the call over to Mr. Hamm. Please proceed sir.

Harold Hamm

Good morning and thank you for joining us this morning everyone. As you may have seen in our press release this morning, Continental reported outstanding results for the third quarter more than doubling our operating income and net income compared to the second quarter of 2009.

In line with other concentrated E&P companies, our performance was driven in large part by increased crude oil prices and Continental’s case from realized products of $53.44 per barrel in the second quarter 2009 to almost $59 in this third quarter. It is also important where our operating improvements during the third quarter, we reduced production expense to $6.50 per Boe which was 9% lower than the second quarter this year and 21% lower than the third quarter of 2008.

We continue to reduce average drilling days per well on the Bakken and managed completed well cost. Our average spud to rig release was 24 days in this third quarter down from 28 days in the first half of 2009 and 45 days from last year. Well cost in North Dakota is around about $5.4 million based on 18 stage fracs.

Finally, the initial production performance of our wells remain very encouraging. The performance retains yielded continue to improve in operating earnings and net income from the first quarter 2009 to the second and third quarters.

We’ve progressed this year from an operating loss of $38 million in the first quarter to operating income of $26 million in the second quarter of 2009 we’ve more than doubled this in the third quarter reporting $59 million in operating income, the same with net income, from a net loss of $27 million in the first quarter of year we delivered net income of $14 million in the second quarter and more than doubled that to $35 million in the third quarter of 2009.

As commodity prices were following up now risen by 2008 our teams raised their performance while reducing costs. This was critical to Continental’s success this year and the team’s excellent execution will have even greater impact as we complete 2009 and go into 2010. We’re aggressively accelerating drilling activity as we announced this morning.

Our capital expense budget of $650 million for 2010 should provide a tremendous opportunity to compound the value of what we’ve earned in the downturn. Continued excellence in execution combined with a four fold increase in operating drilling rigs over the next 12 months presents a significant value creation opportunity for the company and its shareholders.

Our goal is strong production growth and even stronger growth in cash flow in 2010 setting this date for 2011 and beyond. We’re focused on a growth path that organically doubles our proven reserves over the next five years. 2010 of course will be an essentially strong first step. We face a different kind of challenge in the next 15 months.

As you recall we entered 2009 with a backlog of 40 completions that grow production growth early in the year. It was part of tailwind behind us. In the fourth quarter 2009, and early 2010 on the other hand we are accelerating drilling activity to create growth momentum.

What are the keys to finishing 2009 on a strong note performing at a high level of 2010 you may ask. First we expect to see strong crude oil prices and some improvement in natural gas prices going forward. Capital discipline remains a cornerstone of our business model here at Continental. If commodity prices don’t support our plan, we’ll dollar back as we did in like 2008. If those prices strengthen, we will accelerate even further.

With that contingency in mind Continental is now hitting the accelerator in the fourth quarter and upping our exit number of rigs to 12, versus the previous target we had of six. In 2010, we plan to invest $650 million in CapEx, with 87% of that invested in drilling and related operations, what we call operational CapEx. We planned at peak at up to 23 operated drilling rigs by mid year.

The Bakken shale play which led our growth in 2009 will be the primary focus again in 2010. We expect to have up to 15 rigs in the Bakken by mid year, with all but one of those in North Dakota.

In terms of CapEx allocation 66% of our operational CapEx or $373 million will be invested in the Bakken shale play. We plan to participate in completing 61.9 net wells in North Dakota and 4.6 net wells in Montana next year. By the way over in Montana, this would leave us with more than 50 identified well locations yet to be drilled as part of our 328 acre in-field drilling program in Richland County. As we said we have more than 800 net potential drilling locations there in North Dakota based on 640 acre spacing.

Our second priority will be the Arkoma and Anadarko Woodford plays in Oklahoma. We’ve allocated $84 million or 15% of operational CapEx to development and exploration drilling in both Southeast and Central Oklahoma. On average, we’ll have three active rigs in the pipe throughout 2010.

Finally, we are getting busy again with $66 million in operational CapEx dedicated to completing the patent drilling for a water flood project in Cedar Hill units, as well as further development of the Medicine Pole Hills and Buffalo units.

Pulling CapEx from this project in late 2008 and 2009 has reduced a big production expectation for the units, but again as we have said before, this will not change the recovery of reserves at all. We simply delayed the flat to peak and pushed out the rate of recovery. In total our 2010 investment should generate production growth by approximately 10% and set us up again for solid growth in 2011.

Stepping back, what should investors infer from our plans for 2010. First, Continental’s teams did a good job managing through the downturn, maintaining our capacity to re-accelerate growth when crude oil prices came back to us. Aside from a high level of operational execution, we strengthened and provided additional flexibility to our balance sheet, issuing $300 million in 10 year bonds at a good rate.

Second, we not only maintained our tremendous inventory of drilling prospects in the Bakken and other plays, we added to them 70,000 net acreage this year in the Bakken alone. Finally, we strengthened the capabilities of our teams. We brought in new talent with drilling and completion processes and set new standards for performance that will pay off in a huge way as we reaccelerated our drilling program.

I learned a long time ago that you get better in a downturn, you innovate and you prepare for better days ahead. Well we did, better days are here again. We are primed and beginning to roll.

With that I will turn the call over to Jeff Hume, Continental’s new President.

Jeffrey Hume

Thank you Harold. Let me provide you some additional detail on third quarter performance, 2010 CapEx and guidance, and then we will be ready for some Q-and-A.

For the third quarter of 2009 our Bakken production grew to an average 12,524 net drills oil equivalent per day, up 30% over the third quarter of 2008, and up slightly over the second quarter of 2009. All of the growth came from the North Dakota Bakken, where production doubled compared with the third quarter of 2008, and was 11% higher than the second quarter of 2009. Production in the Montana Bakken decreased due to our deferred drilling program.

During the third quarter of 2009 we completed or participated in completing 21 gross 7.6 net wells in North Dakota, which 12 gross 6.4 net were 34% completions. Results continue to be very favorable with seven day initiate production range for the total of 21 gross wells averaging 761 barrels of oil equivalent per day. This is slightly above the average 737 barrels of oil equivalent per day for wells completed during the second quarter of 2009. Again, these are seven day initial production rates which is what we have consistently reported.

Of significance, we have been monitoring historical performance of our Bakken wells and recently increased the average reserve model for our Bakken wells to 430 gross Mboe per well. We believe that the improved performance is a result of fracing experienced gained over the last several years in the play, and increasing the number of frac stages and the amount of sand in each stage.

Year-to-date we’ve more than doubled the amount of sand in our completions from 800,000 pounds and 14 stages in January, to 1.9 million pounds in 18 stages recently, and we’ve increased fluid volume 50%. As you have seen these changes have yielded positive results. We expect that well costs will remain in the $5.4 million range, assuming 18 stages due to drilling efficiencies and lower service and material costs.

In terms of exploratory activity in North Dakota we are completing a key exploratory horizontal Bakken well in Mercer County at this time. The trax of 1-31H, a 91% working interest well, was drilled at a total depth of 19,065 feet successfully frac and has begun testing. We expect to have initial test results in the few weeks, but we saw encouraging shows while drilling.

During the quarter we continue to build our acreage position in the Bakken play. We added 70,000 net acreage in North Dakota since year end 2008, to the point we now have 650,000 net acreage in the Bakken, with 75% of that in North Dakota. We have four operated drilling rigs in North Dakota, Bakken at this time, and plan to exit the year with six operated rigs, which is one more than originally planned.

During 2010 we plan to accelerate our phase of drilling to expand our Bakken fields and North Dakota and Montana. We also plan to begin development operations using ECO-pad drilling. We should have our first ECO-pad rig drilling by year end 2009, and plan to have up to 15 operated rigs drilling in the Bakken by mid year.

In our Red River units, production averaged 13,942 barrels of oil equivalent per day during the third quarter, which is essentially flat since the beginning of the year. In Cedar Hills, we continue to convert producers and air injectors to water injection wells and have 22 wells yet to be converted. During the quarter, we completed two salt water injection wells also.

As you know we continually monitor and update our production stimulation model for Red River units, and our most recent update indicates production peaking in mid 2010 at between 15,500 barrels of oil equivalent per day, reflecting the slower pace of conversions during 2009 to conserve cash.

Before we leave the Rockies, I might mention that we plan to begin drilling a second well in our North Dakota Lodgepole Discovery by year end 2009. We announced in September the discovery well, the Laurine Engel 1-17, which initially produced a restricted flow rate of 463 barrels of oil per day, and continues to flow at a similar rate after two months. This discovery is in addition to some large Baltran, where reserves per well historically average $1.4 million barrels of oil equivalent per well. Continental owns 33% working interest in this non operated project.

Related to production growth in the Williston, we are often asked about pipeline take away capacity. Several infrastructure projects were either completed in the past 12 months or are currently completing. Even if industry production grows significantly in 2010, we don’t anticipate the return of take away capacity constraints like we saw in 2008. There is plenty of capacity for the foreseeable future.

In the Michigan Trenton/Black River play we recently set pipe on two new wells and are currently drilling a third. As you may recall, this is the Albion-Scipio field where we have used 3-D seismic to identify these very prolific targets. The two wells in which we have 83% working interest, had encouraging shows, and we will be completing them in the coming weeks. We have 16 additional 3-D defined locations in inventory to drill.

In terms of 2010 capital expenditures, our $650 million budget is generally in line with projected cash flow using the current strip. Here we cover the fact that our primary focus remains in North Dakota, Bakken, but we will also be investing more in the Montana part of the play, the Red River Units, the Arkoma and Anadarko Woodford plays, and additional drilling in the Trenton-Black River play of southern Michigan.

Other than operational CapEx, we noted in the release that we plan to invest $73 million next year in land CapEx, majority of which would be for new leases and extensions in North Dakota and Oklahoma. We don’t have significant expiration exposure in 2010 and what we have is being managed proactively. We don’t see material threats in this area.

Finally, I would like to give you a little color on our guidance. We plan to grow production approximately 10%, with roughly the same crude oil and natural gas production mix that we have today. We’re leaving our guidance on crude oil differential to same levels that we guided into 2009, although more takeaway capacity might be expected reduced average differentials. We anticipate offsetting pressures as crude oil prices strengthen during the year. The rest of our guidance speaks for itself.

In closing, I echo what Harold said about the opportunities we see in front of us. We are very excited to be re-accelerating drilling. If the prices support us we expect 2010 to be an excellent year that will reward our investors for their faith in us and our growth strategy. Our commitment is to execute at a high-level and deliver excellent results.

With that we will now be happy to answer your questions.

Question-and-Answer-Session

Operator

(Operator Instructions). And our first question comes from the line of John Freeman with Raymond James; please proceed.

John Freeman - Raymond James

Good morning guys.

Jeffrey Hume

Good morning John.

John Freeman - Raymond James

First question I had, I’m trying to get a sense of how to think about the EURs at the end of this year in the Bakken. Last year they were booked at about 365,000 barrels, your reserve engineers have been historically really conservative, but we’re seeing seven production rates continue to trend higher. I’m trying to get a sense of kind of what you would expect that number to be, just a ballpark number?

Jeffrey Hume

John, I believe we’ll see the reserve engineers increasing that. We’ve internally, as we just announced, increased our model to 430,000 barrels of oil equivalent on average, and I believe we will see the reserve engineers getting close to that number on our recent results, the last six months in the North Dakota Bakken.

John Freeman - Raymond James

Okay, and then on the 439,000 acreage roughly that you had in North Dakota and when you did the test to determine that the three to four, at least on half of your acreage, you also believe that it’s a separate reservoir, is there plans to do additional tests on that acreage to further confirm that or you feel like it is good to go, half your acreage is going to be the separate reservoir.

Jeffrey Hume

Well, just as part of our plan we’ll continue to be doing testing just as far as the development. Internally we are very confident that we have separate reservoirs, we are seeing that with production from our very severe test at the Mathistad 1 and 2. We will have several wells and we’ll be drilling second wells either in the middle of Bakken offsetting a Three Forks well or a Three Forks well offsetting an existing middle Bakken in our drilling plan in the next six months. So we’ll continue to confirm our views on the fact that they are separate reservoirs and continue to prove that.

John Freeman - Raymond James

Okay, and then looking at the differentials for the quarter on the crude side, the crude differentials of 939 is almost the same as it was in the third quarter of ‘08, which was a little bit surprising to me. I understand obviously there is going to be more takeaway capacity coming next year, which you’ve laid out in those presentations on multiple occasions, but I am trying to get a sense of why that number was so high in the third quarter.

Jeffrey Hume

I think that difference John, is just the market refiners are discounting a little bit more. It’s not on the field or pipeline transportation end, it’s at the market itself. Even though the NYMEX price is strengthening, we’re seeing the refiners being a little more reluctant to pay that price, but that’s what the pressure was on that differential.

John Freeman - Raymond James

Okay, and then just trying to think about it for the fourth quarter. I mean historically the fourth quarter, the differential is the highest. So I should assume that it trends even higher from the 939 in the fourth quarter, is that the right way to think about it?

Jeffrey Hume

Yes, but I think it would be very slight if at all. I mean right now we pretty well got October-November locked in and we’re not going to see much pressure on that John. So I think we’ll see close to maybe a slight increase for the fourth quarter over the third.

John Freeman - Raymond James

Okay, and then last question and I’ll turn it over to somebody else. In the 2010 budget it wasn’t broken out for Trenton/Black River in terms of how many net wells you would expect to drill in 2010 in Trenton/Black River?

Jeffrey Hume

For the year, it looks like right now we’ve got scheduled 5.6 net wells at the 13 gross and we have right now in our existing inventory from wells we’ve identified from our 3-D. We’ve got 16 locations remaining, and as you look ahead, we’re right now shooting at some additional 2-D data out there, and to expand basically our footprint out there and also have plans to choose some additional 3D. So we see the program to continue to grow out there and we’re very encouraged with what we’re seeing and plan on continuing to invest there.

John Freeman - Raymond James

Great. Much appreciate it guys, and congratulations on the promotion Jeff.

Jeffrey Hume

Thank you John.

Operator

And our next question comes from the line of Steve Berman with Pritchard.

Steve Berman - Pritchard Capital Partners

Good morning gentlemen. Could you talk a little bit about your thinking in drilling on the operated basis, pretty much all Three Forks/Sanish wells versus Middle Bakken wells, what was your thinking behind that?

Jeffrey Hume

Steve, this past year was to really build our data base on the Three Forks/Sanish across the field. As you know, we’ve got a very large area that’s acreage spread over 120 miles north and south along the Nessen anticline. So we wanted to build our database on that, we had very good information on the Middle Bakken from drilling from last year.

And so, now we fell very comfortable that we have very strong reserves in both Three Forks/Sanish and Middle Bakken all along that area, and that’s why we’re stepping forward with development plans with the ECO-pad, where we’re going to harvest both of those horizons. So during next year we’ll be bringing in more and more development rigs to start filling in behind the current rigs we’re working with, one well for 1280 and hold our acreage.

Steve Berman - Pritchard Capital Partners

And when you go all the way up to the Northwest and to divide county, those results seem pretty good. I mean there has been a whole lot of activity up there. What’s your thinking at this point on divide, and do you have a lot of acreage all the way up there?

Jeffrey Hume

We don’t have a lot in divide, we’ve got quite a bit in the Burke County area and we’re very, very strong up into there. Our northern, Norris area is very strong. We’re seeing very good results in the north end.

Steve Berman - Pritchard Capital Partners

Okay, and then down in the Anadarko Woodford, in terms of accelerating your activity there next year, is this a function of what you’re seeing and what you’ve drilled so far, is it a function of what Ximerex and Devon are doing there. What’s the take away so far?

Jeffrey Hume

Steve, all of the above we’re seeing very good results in the Woodford in the Anadarko basin. Devon and Ximerex are having very strong results. We drilled our young well and announced that last quarter to the west of Canofield, very, very strong well, one of the stronger wells in the field. We’re currently just staring an offset well, McCalla well down in Brady County to get a new test in that area.

As we previously announced we had some frac fluid in compatibility with formation fluids. We are going to correct that on this new well, we’re hoping to have good results in that area, have strong acreage position down there, and we continue to test on our Brown well to the northwest. So we are very encouraged by the play and dollars we are putting in there next years, to continue to develop our position in that area.

Steve Berman - Pritchard Capital Partners

One more and I’ll let someone else go. Getting back up to the Bakken, and this big increase in sand you are using, what kind of mix between sand and ceramics are you doing on the slope?

Jeffrey Hume

Steve in the separate portion of the basin, the deeper portion, we’ve been predominantly ceramic, expect for the 100 mesh leading. In the northern area where we are a little shallow and have lower frac gradient, we are currently tailing in with ceramic, we’re finding that that gives us a little bit better permeability near the well bore pack, and it also keeps the sand in place a little bit better.

We’re not seeing much sand coming back by putting the ceramic in there. I think it’s just due to the roundness of the ceramic grains giving us better permeability, and not as much differential pressure near the well bore. So, we’re seeing very good results with that and I don’t have a percentage number, but we can sure get that for you if you like.

Steve Berman - Pritchard Capital Partners

Okay Jeff, thank you.

Operator

And our next question comes from the line of Ronnie Eisenmann with JP Morgan.

Ronnie Eisenmann - JP Morgan

Hi, good morning guys. Just a quick question going back to that 430,000 barrels per well in the Bakken, is that a blend of the Bakken and Three Forks/Sanish?

Jeffrey Hume

That is correct. What we’re using Ronnie is the same model for both horizon, so we’ve not seen one have a huge difference in the other as you look across the field. We’ve seen the Three Forks/Sanish have slightly higher results but I think that’s because we drill more Three Forks/Sanish wells this year as we continue to modify our frac stimulation design. And I think we will see similar results in both horizons.

Ronnie Eisenmann - JP Morgan

And do you expect, I guess since you are seeing better results, do you expect that 430 to continue to increase over time?

Jeffrey Hume

Rick, I’ll pass this to you.

Rick Muncrief

A lot of this is going to be based well performance, I think we’re going to take any realistic, yet to maybe slightly conservative, view of that and we’ll say that we’ve had some of our wells especially in the Antelope area are very strong producers. And it look like have high EURs. I think time will tell, we’ve been encouraged with some of the modifications we’ve made and some of our completion techniques recently that have trended us up higher on our EUR. This is what took our model from the 382 up to the 430.

Ronnie Eisenmann - JP Morgan

Okay. Great, thanks. That’s all I have.

Operator

And our next question comes from the line of Subash Chandra please proceed.

Subash Chandra - Jefferies & Co

Yeah Jeff congratulations. The Woodford, could you go in to the economics there sort of what you are saying well costs are at the moment and on what type of lateral?

Jeffrey Hume

Are we looking at the Arkoma or the Anadarko.

Subash Chandra - Jefferies & Co

First Arkoma and then Anadarko.

Jeffrey Hume

Okay. In the Arkoma AMI our drilling completion cost are around $3.6 million at this time, and we are seeing about a 4.1 BCF EUR and that’s with a 4100, 4200 foot lateral with 9 of 10 stages of completion, we’re seeing at $6 Nymex price at or around a 34% rate of return on that.

Subash Chandra - Jefferies & Co

And Jeff, what do you think that cost was a year ago?

Jeffrey Hume

That cost was, for our wells it was probably around 3.8 or 3.9. Last year we drove our cost down in the Anadarko Woodford in the Arkoma as prices per rigs and goods and services went up I guess due to the drilling efficiencies or our teams did an excellent job there. So most of the gain has just been on the rig and tubular cost going down and rig services going down. So that’s pretty much the gain on the reduction in price that we’re seeing this year.

Subash Chandra - Jefferies & Co

Okay.

Jeffrey Hume

In the Anadarko Woodford, right now we are AFEing those wells at around $5.7 million where we think we’ll have an average EUR of somewhere close to 6 BCF or above, that’s going to yield $6 of NYMEX price 39% rate of return on that also. So, both of those place are very strong and we’re excited, as we gas prices start to move up we feel that 2010 we can have significant movement in gas price and definitely in 2011.

Subash Chandra - Jefferies & Co

And these, in the Arkoma are you seeing -- do you have sort of a substantial non-op program going on, and sort of do you see the type of cost per well fairly predictable in the operated as well as at non-operated program?

Jeffrey Hume

We have. The other operators have really worked on their efficiencies also, and the entire industry is doing a great job with that, and we do have a significant non-op position in the Arkoma Woodford with about 25% of our acreage being non-operated.

Subash Chandra - Jefferies & Co

Okay. Second I guess, is the net well count do you have for ‘09?

Jeffrey Hume

We announced our $390 million budget increase. Our net count for the year looks like it’s going to be right around 51, 52 net wells.

Subash Chandra - Jefferies & Co

Okay. And then finally are you guiding, I was just looking at the annual number for production. So it seems to imply a sequential decline in Q4?

Jeffrey Hume

We’re going to be fairly flat, maybe a slight decline and it’s just due to the drop off of bricks that we had going into the third quarter and through third quarter. As you are well aware the production growth is about 90 days in lag of rig operations, that’s why we’re trying to get rigs accelerated during the fourth quarter.

This year we had the good fortune of crude oil prices improving to allow us to expand our capital budget increase rig count to get a running start on 2010. So I think we’ll see the best that we’re making in 2010 fourth quarter really start showing up in early 2010.

Subash Chandra - Jefferies & Co

Have you seen any type of potential curtailments, I mean clearly not in Q3, but anything happening real time out of the Woodford or anything related to full storage.

Jeffrey Hume

We’ve not witnessed that in any of our fields, Subash.

Subash Chandra - Jefferies & Co

Okay, great. Thanks much.

Operator

Our next question comes from the line of TJ Schultz with RBC Capital.

TJ Schultz - RBC Capital

Hi, guys. Just a little more clarity on the ramp in rig count. I know you said you’re going to be at 12 by year end with six of those, it sounds like the North Dakota and 23 by mid year with 15 in North Dakota, just trying to get understanding of where the other six rigs will be at year end and the other eight rigs will be at mid year kind of a break out there?

Jeffrey Hume

Okay, at year end we’ll probably be we’ll have six North Dakota, we’ve already mentioned we’ll have one in the north in the Montana Bakken, one in the Red River Units, one in Anadarko Woodford, two in Arkoma Woodford and one in Michigan. That’s best of 12 that we will be exiting the year end.

TJ Schultz - RBC Capital

Okay. Then mid year just kind of if there is 15 in the North Dakota, Bakken and you’re going to have three averaged out through the year and the Anadarko and Arkoma and then difference would be Michigan and Red River, is that the right way to think about it?

Jeffrey Hume

Right, yeah. Well I have three in the Arkoma Woodford going about mid year, one in the Anadarko Woodford, we’ll have one going in Michigan we anticipate, plus a couple of other, well we’ll have probably one and possibly two rigs going up in the units at that time as well.

TJ Schultz - RBC Capital

Okay, great. And then just quickly on Montana, the rig you are drilling there, are you focusing or Bakken or Three Fork Sanish?

Jeffrey Hume

In the Elm Coulee field that is all middle Bakken development. In that field we only have the upper Bakken shale and the Middle Bakken dolomite developed in the field proper where we’re drilling the 320 acre in-field. So it will be a middle Bakken well or wells that we’re drilling.

TJ Schultz - RBC Capital

Okay, thanks guys.

Jeffrey Hume

Yes sir, TJ thank you.

Operator

And a final question comes from the line of Eric Hagen with Lazard Capital. Please proceed.

Eric Hagen - Lazard Capital

Hey Jeff, congratulations again. In the Mercer County well, I assume this is the first well you have drilled there. How much acreage do you have there, and is there any other industry drilling around that?

Jeffrey Hume

We have in the immediate area around that the tracs we have around 40,000 acres in that immediate area on to the south and the west altogether, including that we’ll have around 80,000 or 85,000 acres in that area. There is room to add some acreage in there, but we have a pretty solid block through there where we represent it.

Eric Hagen - Lazard Capital

Is that a Three Forks well or is that a Middle Bakken?

Jeffrey Hume

We drill that in the Bakken.

Eric Hagen - Lazard Capital

Great. That’s all I have, thank you.

Operator

And we do have one last question from the line of Andrew Coleman with UBS.

Andrew Coleman - UBS

Hi, good morning folks. I had a question for you on the 18 stage fracs, I guess how many wells do you think you would have to drill and what sort of signs are you looking for that would give you an indication that you could take it up to some of the higher frac stages that some competitors are doing out in the Bakken?

Jeffrey Hume

Well, Andrew, the good thing is production data is shared by everybody, so we will be able to analyze other peoples, the other companies that are going higher than 18 stage fracs. Right now the 18 stage frac is doing a very, very good job. We’ve stepped to that, we’re seeing good results. At some point there will be diminishment return on the cost of performing those frac stages, and the complexity of it.

So we feel very comfortable with 18 stage. We’re going to be getting an efficient frac, but we will continue to monitor that, and probably during the year, we will do a few with more stages just in certain areas where we have good well control to see if it does help us in those areas, but right now, we’re going to stay with approach we’ve taken over the last year and be very definite in how we move up and watching the performance and getting a base line before we run too far.

So we’re seeing an improved volumes with what we’re doing. The biggest improvement we’ve seen this year has been getting more sand into rock, and placing the sand and how we’re placing the sand. And there is a lot of idiosyncrasies there that I can’t describe on a conference call that the engineers are working on just how they are ramping the sand into the formation, how we’re watching it and effectively getting the jobs off.

So, we’re taking the step to 18 stages, we’ve performed several of those now, feel very comfortable with that and are getting solid results and we’ll continue to monitor what the entire industry does.

Andrew Coleman - UBS

If I heard it right at the beginning, what was the amount of pounds of sand for 18 stage or per stage right now?

Jeffrey Hume

Right now the 18 stage frac, one we just finished 1.9 million pounds. So, just a little over 100,000 pounds per stage.

Andrew Coleman - UBS

Okay, great. The last question I have was, looking at the CapEx budget of 2010, how much above the maintenance CapEx levels are you in the I guess non-Bakken regions?

Jeffrey Hume

Well, let’s go back and do some math on that, in the non-Bakken regions. Andrew, I am going to have to sit down and pass it, just couldn’t give you an answer off the top of my head of what it would be just in those regions.

Andrew Coleman - UBS

Okay, fair enough. I can follow up with you offline. Thank you.

Operator

We do have a last-minute question from the line of Mike Breard with Continental Resources.

Mike Breard - Continental Resources

Yes, if oil prices were to increase substantially more than what you’re looking at now, I assume you would be adding extra rigs, again would you put most of those in the North Dakota Bakken or would you spread them out a little more?

Harrold Ham

Well, obviously the North Dakota Bakken is one of the most prolific place we have going. So high rates of return, we have great confidence in crude oil. So, if your thought just kind of prove that price do go up, sure with bigger price we ramp up first.

Mike Breard - Continental Resources

Okay, and you have the staff to handle considerably more rigs than 23. So, I assume you won’t hesitate to add rigs as prices go up?

Jeffrey Hume

We would not, and so far rigs have been available to us, easily available, due to slack drilling of natural gas prospects. So, we’ve handled about 30 in the past, so we could ramp up further that’s for sure.

Mike Breard - Continental Resources

Okay. And just one last question, are these rigs, are you signing term contracts or well to well, or what sort of contracts are you signing in general?

Jeffrey Hume

No, these are people we have worked with in the past, and they are glad to put those rigs back to work and those crews back to work. So right now we’re not signing long term contracts.

Mike Breard - Continental Resources

Okay. Thank you.

Operator

And there are no further questions in queue at this time. I would like to turn the call back to Mr. Hamm, Chairman and CEO for closing remarks.

Harold Hamm

Well, thanks everybody for joining us this morning. We’re very excited about prospects that we have here at Continental going forward. We have got a good plan laid out for 2009 and end of 2009 and on to 2010 and ‘11 and we have as part of our growth plan over the next five years.

As we’ve indicated in the past, we’re on a path to more than double our reserves in the next five years. It turns out that the Bakken as we’ve predicted is better than we expected with the 24% addition coming on it’s turned out to be a really nice part here in onshore US.

So with that, we are going to sign off this morning and thank you very much for joining our call.

Operator

Thank you for you participation in today’s conference. This concludes the presentation. You may now disconnect and everyone have a wonderful day.

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Source: Continental Resources Inc. Q3 2009 Earnings Call Transcript
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