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Continental Resources, Inc. (NYSE:CLR)

Q3 FY08 Earnings Call

November 6, 2008, 10:00 AM ET

Executives

J. Warren Henry - VP of IR

Harold G. Hamm - Chairman and CEO

Jeff Hume - Sr. VP of Operations

John D. Hart - VP, CFO and Treasurer

Analysts

John Freeman - Raymond James

Joseph Allman - JPMorgan

Eric Hagen - Merrill Lynch

Curtis Trimble - Natixis Bleichroeder

Chris Bray - Jefferies & Co.

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2008 Continental Resources Earnings Conference Call. [Operator Instructions]

To begin today's call I would now like to turn your presentation over to Mr. Warren Henry. Please proceed sir.

J. Warren Henry - Vice President of Investor Relations

Good morning, everyone and welcome to our earnings conference call. On today's call we will be describing beliefs, goals, expectations, projections, assumptions and guidance that are considered forward-looking statements. Actual results may differ from those contained in our forward-looking statements.

For additional information concerning these statements and risks, please refer to the company's filings with Securities and Exchange Commission. This morning we published our third quarter 2008 earnings press release which included our 2009 capital budget and guidance.

On our earnings conference call today, Chairman and CEO, Harold Hamm will provide a brief overview of recent achievements and our opportunities for growth. Jeff Hume, Chief Operating Officer will provide greater detail on recent developments, and finally John Hart our CFO will provide some insights on our plans to manage our balance sheet after which we will be ready for Q&A. During the Q&A, Jack Stark, Senior Vice President for Exploration will also be available.

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 join us on the call this morning. As a result, the world financial crisis, much as changed in the energy industry since our last earnings conference call.

Our earnings announcement this morning reviewed our successes in third quarter and outlined our outlook has changed in response to the resulting declining in crude oil and natural gas prices since July.

Like others in the oil and gas industry, Continental's response to the current level of commodity prices have reflected and has reduced operating rig count and as 2009 capital expenditures budget. In 2009 we look forward to another year of strong growth in production and reserves but the expected rate of growth in 2008 exit rate have changed due to lower commodity prices and resulting expected cash flow.

In contrast to the volatility and commodities the key operating and financial strengths that define Continental Resources remain the same. I'd like begin this morning by highlighting how we plan to leverage these strengths to create value in a changing, operating environment.

First, we're committed to operate generally in line with cash flow and we highly value our strong balance sheet. This is particularly important in the current environment for low commodity prices are compounded by the tightness of the credit markets. We have not and will not over extend ourselves. We will manage our balance sheet with minimal debt compared to cash flow, while being flexible to expand operations quickly, if pricing improves and circumstances dictate.

In addition, our strong balance sheet reduces the need in most circumstances to hedge our production. We're currently 100% un-hedged and consequently we'll have no counter risk; counter party risk, in this unfavorable credit market. The company will receive the full benefit, as prices recover.

By the way, another reflection of our prudent approach is that Continental Executives and Directors are prohibited by policy from buying CLR stock on margin. This prevents executives from being force to sell shares until volatile market.

Secondly we're a low cost producer with industry leading operating margins. We generate our own drilling prospects in house and have built our acreage positions in key resource plays at moderate cost rather than paying top dollar to acquire a proven acreage from others.

By serving as operator for the majority of our properties we also have a greater control over drilling and completion cost and the timing at those costs. We're using our man power to bring down service cost as quickly as possible to get in line with lower commodity prices as we speak.

Although current prices seem low after the dramatic decrease since July, they are actually returning to about where we were in the third quarter of 2007. Our projects are very viable than is price environment and are expected to improve as service prices are reset.

Finally, for we are conservative in our business discipline, we will remain aggressive as an exploration company and pursue crude oil. The Bakken shale in North Dakota in Montana has highest potential oil play in a lower 48 U.S. today.

We're the leading lease holder in the play. We also have strong lease positions in many other key national gas resort plays in U.S. With our 1 million acres in the U.S shale resort plays, we have a tremendous opportunity to build reserve over the next several years, especially the North Dakota Bakken.

The SEC is currently reviewing these rules on reserve capital for resource plays. We hope that the SEC reserve rules will be changed to provide greater transparency as to the quantity and value of these reserves and fuel resource plays.

As a reminder, even with all the attempts on the Bakken its still very easy to overlook the fact that year end 2007 Continental's acreage in North Dakota Bakken represent only 5% of our total crude reserves. And since July 1st of this year, through acquisitions, leasing we've added another 149,000 net acreage into play.

Additionally, our success with the first nine Three Forks/Sanish wells further expands our reserve growth potential in North Dakota Bakken. To summarize, we see excellent opportunities in the current environment to capitalize on Continental's operating and financial strengths. We are low cost producer with a long history of operating inline with cash flow. And we have tremendous potential to grow reserves. With that say let's view the third quarter.

Continental Resource again delivered strong operating and financial results. We increased net income 87% and cash flow was up 79% compared with third quarter last year.

We continue to improve the drilling and completion results compared to the second quarter of 2008. For the third quarter ended September 30, 2008, the company reported net income of $105.3 million or $0.62 per diluted share compared with $56.4 million or $0.33 per diluted share for the third quarter of last year.

Oil and natural gas sales were $286.2 million, an increase of 72% of our oil and gas sales for the third quarter of last year. The company's average sales price per barrel crude oil equivalent was $93.21 with most recent quarter compared with $62.61 with the third quarter last year.

EBITDA was $238.3 million compared with $132.8 million for the third quarter of 2007. Continental's production averaged 33,297 Boepd for the third quarter of 2008 an increase of 5% over the second quarter of 2008 and 13% over third quarter of 2007.

The company exit the quarter with production averaging 34,889 Boepd for September 2008. And you saw in the release production increased significantly in the North Dakota Bakken and Arkoma Woodford Play of South East Oklahoma, with sequential quarterly gain of 65% and 24% respectively. Our 2009 Capital expenditure budget is $609 million with $541 million allocated drilling and completion activities. Drilling operation next year will be focused on the North Dakota Bakken and to the lesser extent in the Arkoma Woodford. For our 2009 operation are designed to be in line with cash flow, please keep in mind that oil prices remain volatile.

This is a scale back CapEx budget that we ready to increase as the commodity price environment improves. With that brief overview I'll turn the call over to Jeff Hume to discuss our operating progress in various resource plays. Jeff?

Jeff Hume - Senior Vice President of Operations

Thank you Harold. In the third quarter we continue to grow our North Dakota Montana Bakken program and we're particularly pleased with the continued increase in average completion rates and results from ongoing evaluation of the three Forks Sanish reservoir. We increased our acreage position to 604,000 net acres during the quarter so Continental remains the largest lease owner in the play.

Net production from our Montana North Dakota Bakken properties combine was up 14% over the second quarter of 2008 averaging 9631 net barrels of oil equivalent per day. This growth represent 65% increase production from the North Dakota Bakken and a slight decrease of 3% production from Montana Bakken compared to the prior quarter.

During the third quarter; we completed 16 gross 5.3 net middle Bakken and Three Forks-Sanish wells in North Dakota forward play. With average 7 day production period test rates of 602 barrels oil equivalent per day up 22% over the Bakken completions reported by the company for the first half of 2008.

And by the way in the reminder of my remarks they all references to production will be based on 7 day test proved results which is our standard reporting metric. Anyway the third quarter of 2008 mark third consecutive quarter in which we've delivered significant improvement in well productivity. Improved rates not only reflect our transition to liner and multi-stage frac completions.

But also results we have achieved from the Three Forks-Sanish wells. So far in 2008 we've completed 9 company operated Three Forks-Sanish wells producing in an average rate of 852 barrels oil equivalent per day. This is 48% better than the average rate for company operated middle-Bakken wells completed so far in 2008. Five of these Three Forks Sanish wells produced at rates in excess of 1000 barrels per day. These are the Mathestat, Croft Omar, Maryann and Morris wells.

Two more produced a test rates of more than 650 barrels of oil equivalent per day. These Three Forks Sanish completions we're strategically positioned throughout our acreage along the Nesson anticline and. and we encounter consistent comparable results over area expanding 100 miles North to South

Going forward, we plan to focus the majority of our drilling in North Dakota on the Three Forks Sanish formation to further test its potential. We currently have nine of the companies ten operator rigs in North Dakota targeting the Three Forks Sanish.

The latter half of 2009, we also plan to drill middle Bakken wells and Three Forks Sanish producing units to test the three of our Three Forks Sanish in middle Bakken or separate segregated [ph] over the play.

Our drilling program in Montana Bakken during the 3rd quarter focused on drilling single leg horizontal well and completed them using liner and multi-stage fracs, in other words the approach that has been most successful in North Dakota.

Average 7 day production period test rate was 391 barrels of oil equivalent per day for the third quarter, up 33% over second quarter completions and up 50% over first quarter completion in Richmond County. We also announced the formation of the Montana Bakken EOR consortium which plans to initiate the CO2 injectivity pilot project in Richland County.

The consortium plans to start injecting CO2 before year end 2008 to inject jet gas for one month then shed into well for one month. Well within the produced back and the data will analyzed to term the effectiveness of using CO2 in [ph] in the play.

The company has allocated $281 million in 2009 operational CapEx in North Dakota, Montana, Bakken where 52% of this operational CapEx budget to grow 131 barrels or 44.1 net wells into in play.

Now let's look the Red River units. We continue to drill infield wells with 5 rigs planned through the third quarter and added the 6th rig to drill additional water supply wells to meet expanded water injection volumes announced earlier this year. During the quarter, Timney [ph] wells were complete as produces. We converted 4 producers to water injection wells to exist in horizontal wells had laterals extended and 2 vertical wells have horizontal laterals added. A fourth water supply well was added to bring current water injection to 30,000 barrels a day and the water injection plant was expanded from 35,000 barrels a day to 50,000 barrels a day.

And a second water plant with a 30,000 barrels with a capacity in 2 additional water supply wells are in construction phase and completion... With completion expected this month. And by the way, this plant was put in operation yesterday and currently has injection of around 45,000 barrels a day and will be increasing.

Our infield development program will be slowed by 2 rigs by year end and keeping with our announced 2009 budget. This reduced rate count will lower the ultimate peak rate slightly to approximately 19000 barrels of oil equivalent per day which will occur in the fourth quarter of 2009.

However oil fund reserves will not be affected by the slow development rate and we see no benefit now to reaccelerate to keep production rate in the near term even if oil price improve. The Arkoma Woodford continue to provide the excellent results with 34 gross 5.25 net completions during the third quarter. We previously announced completion in the Blevins 1-1 54% working it first well in Huges County. On an average rate of 8.1 million per day during the first week production.

And other recent notable completions is the six well simul-frac in Hughes County Oklahoma that incorporated three pairs wells located in adjacent Luna-Pratt spacing units. These six wells averaged 3.76 million cubic feet per day per well during the first production, first week production. We're currently drilling our first spacing units to 88 per horizontal equivalent density by adding 7 well bores in our Pasquali unit where we have a 56.25% working interest which is located in coal county Oklahoma. These wells will be frac back-to-back with the 3 well and 4 well simul fracs later this month.

Inline with our 2009 capital budget our plan is to dial the current [ph] development program in Arkoma Woodford back to a two rig program for 2009 drilling development wells in a core Ashland area and a lesser number of wells in our e Eastern McAlister exploration area. Other projects have no our initial test wells being drilling and at Arkoma basin, Woodford Shale and [ph] shale. With the company holds 111,000 and 34,000 net acres respectively. We've began drilling two wells and each of these prospects and there is schedule be completed by year end. With that I like to turn the call over to CFO John Hart to discuss our balance sheet.

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

Thank you Jeff with the recent market volatility in credit crises we felt that it would be valuable this morning to discuss our finances in the fundamentals under which we operate. First as Harold noted previously we planned to operate generally inline with our cash flow, accordingly we have maintained a relatively lower debt flow for a company of our size.

In fact, our outstanding debt relative to cash flow is low compared to our peers. We intend to continue operating in this manner maintaining a strong balance sheet which we believe enables us to weather periods of volatility.

At the end of the third quarter of 2008; we had outstanding debt of $229 million and an availability of $171 million as commodity prices declined in recent months we have begun to lower the level of our capital expenditures have there is a lack between the timing of realized, lower realized commodity prices and decreases in capital expenditures. So our outstanding debt has increased to $276 billion as of October 31.

At this level we had $124 million available to draw at the end of October up to our currently established commitment amount. We believe this provides us an adequate cushion given that we continue to reduce capital expenditures and our drilling activity. Our current facility as a bit of background allows us to set note a manner to $750 million.

Our most recent borrowing based recalculation was in the spring and it resulted in a borrowing based $1 billion. Note however, that although our reserves support a larger borrowing base we have not borrowed and do not intend to borrow a high percentage of our borrowing base. With our preference to operate inline with cash flow, we are working to minimize the need for additional external financing. We also intend to maintain a straight forward financial structure. We currently are not a party to any off balance sheet transactions, material leases, volume metric production payments, or any other structured financial products.

As Harold noted previously we are not a party to any derivative transactions. We intend to maintain a very high level of transparency that allows investors to actively asses our operations and risk.

In closing we want to stress that Continental is a strong organization based on some financial fundamentals that should enable us to continue growing and creating value for our shareholders.

Chris, with that I'd like to turn the call over for Q&A.

Question And Answer

Operator

[Operator Instructions]. Your first question will come from the line of Mr. John Freeman from Raymond James. Please proceed.

John Freeman - Raymond James

Good morning, guys.

Harold G. Hamm - Chairman and Chief Executive Officer

Good morning, John.

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

Good morning.

John Freeman - Raymond James

First thing I want to kind of drill down on is Red River in terms of the capital expenditures there I'm trying to understand maybe where I might have been confused previously. My understanding that this year $184 million of it was being spent roughly on the CapEx at Red River that about half of that amount was either infrastructure or water related issues that we're going to have to be duplicating in next year and then with drilling activity going from roughly a little over five rigs to something less than two rigs next year that the reduction at Red River would be able to be a lot more than it looks like it will be for '09? So I guess that's the first question just maybe what and where the disconnect was?

Harold G. Hamm - Chairman and Chief Executive Officer

The disconnect is that the rig count even though we're drop into two rigs, they will continue throughout the year. We're prior when into the first part of the year with a higher number of rigs and we started dropping them out in May, July and November with dropping it down to two rigs will be occurring, spin about the same capital but this submit up out through the year a little bit and not fund and loading our expenditures.

John Freeman - Raymond James

And then were there any other like water related issues, maybe need more water disposable wells or whatever than what you anticipated last quarter?

Harold G. Hamm - Chairman and Chief Executive Officer

Well we... not additional water spy wells but we have, we have quite a bit of capital work over for converting wells into water injection that will be spent because we'll be converting quite a few wells in the first to second quarter, two water injection now that we have the plans that would be taken of production and including on so that's going to be some capital work over money that we go into

John Freeman - Raymond James

Okay. And then since the decline is now seems to be a little bit less even if the peak is lower, can you give me an idea of what that decline are you're expecting now?

Harold G. Hamm - Chairman and Chief Executive Officer

What we're looking at right now is peak brown 19,000 in early in the forth quarter, and that will probably hanging there for about a year it will be fairly flat but close to a year and then we'll start seeing the decline and so will up end of '10 we'll start to see a decline come up for second half little.

John Freeman - Raymond James

Okay. And then last question I'll turn it to over somebody else. Can you give me an idea Trenton-Blac k River next year that the CapEx wasn't broken out for that play and then just kind of maybe how many wells you exact over drill next year?

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

In the Tren Black River, we've got the plans for seven wells in there and in our timing on that is flexible at this point but we have identified we shoot the 3D size make out there and that we had plan to get down this year and have identified of at least nine good looking locations out there and so we'll begin early, we think we we'll probably begin at sometime early part next year just a couple of.

John Freeman - Raymond James

Okay. Thanks guys, guys.

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

Thank you, John.

Harold G. Hamm - Chairman and Chief Executive Officer

Thank you, John.

Operator

Your next question comes from Joe Allman from JPMorgan. Please proceed.

Joseph Allman - JPMorgan

Yes, good morning everybody.

Harold G. Hamm - Chairman and Chief Executive Officer

Good morning.

Joseph Allman - JPMorgan

In terms of service cost could you talk about what are you see in these days in terms of service cost are you trying to see things decline and if so what's declining and where?

Harold G. Hamm - Chairman and Chief Executive Officer

What we've seen is an automatic reduction in diesel prices, they are direct, we bought a quite a bit of diesel on our ridge. And we contacted all the service providers and they're backing off this fuel surcharge that was added during the first part of the year. So we've seen that come off. We're also contacting all service providers and ask them to step back steel doubled and price last year as that works through some of the steel plants and all contributor goods sucker rods on that we will see those prices come back.

This week I saw a letter come through with sucker rods one of the providers of sucker rods to reduce their price by, I believe 9.5%. So that's going to start trickling through as people burn their inventories down and the manufacturing and so I think that will come to greater extent I think the service operators will be coming down after we see some rigs regulation go down from everybody announcements going to Cap Lake in this quarter in early next quarter. And that normally takes four to six months for those service cost to retrieve.

Joseph Allman - JPMorgan

Okay. It's very helpful. Thank you.

Operator

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

Eric Hagen - Merrill Lynch

Good morning. I kind of follow up on Joe's question for question. Of the remaining rigs I think you kind to have 17 by year end, how many of those are on longer term contracts?

Harold G. Hamm - Chairman and Chief Executive Officer

We have a very few on longer term contracts in fact we have... where we have longer term contracts, where would be our very last wells to rigs to take out of place. So, we just are not hamper it at all by rig contracts, so, we're in good shape there.

Eric Hagen - Merrill Lynch

Okay. What do you think so a price threshold for reducing your activity... further reducing your activity in the North Dakota Bakken. I mean if we see oil prices at 50 is that the threshold or you might drop a few additional rigs and high grade your program or is that just too much of a moving target to figure out.

Harold G. Hamm - Chairman and Chief Executive Officer

Well, I think what you're going to see it right now we're very viable at $60 where are at today, we got good rate return of over 20% around 23% rate of return. And I think as you see prices go down even more than that, there's going to be so much pressure on the service industry. The cost will come down, we'll all make it viable in a lower number than that. Right now, I think we could operate down on that $50 range fine and continue to grow.

Eric Hagen - Merrill Lynch

Okay. And the last question it was on this take away issues on the basin can you comment on how much of your oil you have on the truck out in there? What's the outlook for that near-term? What's your outlook for basis differentials?

Harold G. Hamm - Chairman and Chief Executive Officer

Well we're currently moving 5,000 barrels a day on rail and that's on gross barrels we're taking out. So about 40% of that's probably operated barrels that are going out and that's going to be at a basis differential of somewhere around $15. The pipeline is mostly around that $5 to $7 range and then it gets little larger during the winter months when NYMEC the other end of pipelines start getting difference other end of the pipelines we'll see that drill after $8, $9 may be $10 in the months and that will come back and the spring drop back down.

Eric Hagen - Merrill Lynch

Great, that's all I had. Thank you.

Operator

Your next question comes from the line of Curtis Trimble from Natixis. Please proceed.

Curtis Trimble - Natixis Bleichroeder

Sure, thank you, good morning everyone. I just trying to drill down a little bit here and get an idea of cost concerns versus price concern, can you give us and idea sort of completed well cost and the Mountain, North Dakota Bakken as well as in the Arkoma Woodford and kind of which you would expect to see in terms of cost compression in order to ramp activity levels back up there and then maybe an easier question is kind of drilling down a little bit more on the differentials what you need to see in terms of price response because most likely I'm guessing that we'll see both side of this kind of meet in the middle and mid year maybe you talk a little bit more about ramping up. But can you give me an idea of what you look like on an individual well cost there?

Jeff Hume - Senior Vice President of Operations

Sure. Let me first start out giving you the current cost scheme that we have under today's environment and which is coming out of this summer in Arkoma Woodford we're looking at cost between $4.4 and $5.8 million depending on where we at in the Woodford and the depths of the well. And that's averaging around $5 million a well. In Montana Bakken we're at around $5.6 million now on those wells and that's because were going to the liner completion multi stage frac [ph] We announced early we're getting a lot results from there. North Dakota Bakken we're seeing cost between $5.6 to $6.4 million average in $5.8 million and that's the variable layers the number of stage of frac we have on it.

Now to second part of your question is where does it go down to that's a dynamic question it is going to be function whether the drilling cost are going to be, I can see that we could easily have a 10% to 20% reduction in cost during the first half of the year, if the rig count, national slows as we've been reading will happen and what we're hearing people announcing.

So I think we can have steel prices more than doubled last year. So there is room for those to retreat, we're seeing scrap prices back to a normal level as the time functioned everything to the mills and plants so as those cost come down. I think that will allow us to ramp-up our activity is really a function cash been viability of our projects, our projects are very viable today I think its going to be become more viable these costs go down and with I believe as winter comes on you see the prices pick back up model prices are rebound.

Curtis Trimble - Natixis Bleichroeder

And in terms of conversations and maybe around the industry up there, do you here other folks laying down large number of rigs and providing that we do see costs come down and folks start to make the capital budgeting decisions for the second half of the year the May, June July time frame do you think maybe you will get in a scrambled four rigs if you wanted to step up?

Harold G. Hamm - Chairman and Chief Executive Officer

The North Dakota Bakken I think is a play by itself unlike the natural gas resource plays across the country. We haven't seen as many people Bakken our play [ph] on rigs due to the viability the play. We're careful on very consortium as the fact that we laid rigs up there, we might not get them back so, we think that there will be more rigs moved into that play as the plays separate people slowing down, our river basin for instance, that's where most of the rigs come in North Dakota.

Curtis Trimble - Natixis Bleichroeder

And have you seen indications of early movement yet?

Harold G. Hamm - Chairman and Chief Executive Officer

We've seen movement from our river over to the North Dakota for the last three years. That's been found a steady progression I guess.

Jeff Hume - Senior Vice President of Operations

We're receiving calls from rig operators and the gas areas of the Rockies right now. They started calling probably 4 weeks ago and with rigs that are being freed up there, they were able to move into the Bakken. So I think as we see the rebound in prices at the end of some [ph] which price rebounds first and our opinion is going to be oil and I think those rigs will be available to ramp that activity up and we'll be able to handle it.

Curtis Trimble - Natixis Bleichroeder

Very good. How about discussions on additional pipeline capacity coming on have those been slower over the past couple of months due to the fall in commodity prices or there still fairly robust?

Harold G. Hamm - Chairman and Chief Executive Officer

Yes, it is still fairly robust we see a completion of the White Cliffs pipeline. That thing was projected to be online at the end of this year and all indication is only taken oil from the Platteville area before that year end. So that's least what we're hearing and that be helpful. And we're seeing another pipeline try to ramp up to drag reduce and agent slow things the volumes and they're coming out somehow.

Curtis Trimble - Natixis Bleichroeder

I very much appreciate your time.

Harold G. Hamm - Chairman and Chief Executive Officer

Thank you, Curtis.

Operator

Your next question comes from the line of Mr. Chris Bray from Jefferies, please proceed.

Chris Bray - Jefferies & Co.

Hi, good morning guys.

Harold G. Hamm - Chairman and Chief Executive Officer

Good morning, Chris.

Chris Bray - Jefferies & Co.

A quick question, you guys are planning and having 15.5 rigs running next year eight in the Bakken, two in the Red River, where will be other five and half be located?

Harold G. Hamm - Chairman and Chief Executive Officer

We'll have as you said we've eight in North Dakota one in Montana, we've two in the Arkoma Woodford, two in the Red River units and then one or two that would be in Mid Continent and other areas some of our emerging place.

Chris Bray - Jefferies & Co.

Okay. Great. And you discussed in the last call that you were testing 12 stage fracs in some of your Bakken completions what were the results of those and would you be kind of trending towards 12 stage fracs is supposed to 8 to 10 moving forward?

Harold G. Hamm - Chairman and Chief Executive Officer

Yes, we were, we're up to 14 stage fracs now and we have such a small database of 9 completions in the Three Forks/Sanish it's really too early to put a statistical number out there but we do like we're seeing improvement with the additional stages, most of the well bores if we have a nice, unless we have well bore problem we're running 14 stage fracs now.

We just completed a set pipe on the well, that's on the 640 acre, 4500 foot ladder we're going to do at 10 stage completion in the sea. But what the effect of that is, some points it's going to be reduced cost benefit ratio there the additional cost of fracking that were best part of seeing improvement with the addition of stages and Forks issue add additional stages increased the complexity and transfer mechanical problem during the frac. The crews are getting much, much better but during out the prank work and we're feeling more comfortable and we've now fourteen stage fracs complete this things.

Chris Bray - Jefferies & Co.

Okay, great. And as far as the expiration charge went this quarter, could as kind of touch on that and just kind of referring maybe where that came form and what that would look like moving forward?

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

Sure. Expiration expense obviously will vary from quarter-to-quarter. This quarter we had a higher component for seismic charges and those should level off a bit in the fourth quarter but made about $7 million in seismic charges than we had a couple of dry holes of the quarter that added our two or three dry holes in the quarter that added another $6 million to $7 million.

Chris Bray - Jefferies & Co.

Okay. And any additions to your Haynesville acreage or Marcellus in the past quarter and how do you guys look at that moving into 2009 as far as the land grab perspective goes, again continue to add here Bakken acreage and or some of the shale place?

Harold G. Hamm - Chairman and Chief Executive Officer

We're going to continue adding to our Bakken acreage most of our land cost were as far as to the North Dakota Bakken we got about 21% of our land budget target to the Bakken at this point.

Chris Bray - Jefferies & Co.

Okay. Great I appreciate it. Thanks a lot.

Harold G. Hamm - Chairman and Chief Executive Officer

Yes.

Operator

[Operator Instructions]. Your next question is a follow-up question from Joe Allman from JPMorgan. Please proceed.

Joseph Allman - JPMorgan

Yes, thank you, hi again. Jeff where is that CO2 pilot taken place the consortium pilot?

Harold G. Hamm - Chairman and Chief Executive Officer

That's going to be in the, about the center of the Omkoli Field. There's a well bore in there and another operator is part of the consortium. That's case track and will allow us to run our logging tools out there to see the effectiveness of after the flow back post flow back of our CO2 went so in kind of see going to be kind of centered in field where we kind to get a respective sample.

The main focus of the test is just to see how much rock we can contact with the CO2 and then watch the molecules as they come back we will and see what kind of gain we have in there. we've already done laboratory test, slim tube test we get around a over 90%, I think it's around 98% recovery on a slim tube test with poor volume of CO2 going through so it's the process is going to work well the question is how much rock can we contact and the effectiveness so that swelling if any in the well and bring it back. So this will be our first step into getting that data where we can build a simulation model of full scale.

Joseph Allman - JPMorgan

And with just the drilling that's happening so far. What do you think the oil recovery is? And then what's the hope that what kind of recovery, incremental recovery could you get from this CO2?

Unidentified Company Representative

Well, it's too early to really give a specific number on that, but rule of thumb I think we can probably at least double our primary and then go upward. This is a non-conventional reservoir so its just going to depend on how much rock we can contact and... So there's a lot of variables still out there so I hate to speculate much more than that but I think there's a very good possibility if we can that we can double our primary reserves with it.

Joseph Allman - JPMorgan

What is the estimate the recovery from the primary?

Unidentified Company Representative

On all in place.

Joseph Allman - JPMorgan

The produce percentage..

Jeff Hume - Senior Vice President of Operations

We're looking around 250 to 300 million barrels primary. So that's probably your target for secondary right now. It'd be real rough [indiscernible].

Joseph Allman - JPMorgan

Okay, that's helpful. And then I think Jeff you were talking about earlier on the economics of the Bakken [ph] it our oil get to 23% rate of return. I know that's in your slide but what kind of deferential do you assume when you come up with those economics?

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

That... that is $7 differential I believe I don't have that on my sheet here, I believe that's about a 7.

Joseph Allman - JPMorgan

And then when would expect I mean clearly differentials are wider than that. When would expect to get back to that kind of more normalized differential?

Harold G. Hamm - Chairman and Chief Executive Officer

Really you have to look at it over the year. I think we're going to be seeing something close to that over the year to 7... 7 to 10. When would we see that differential, we're already seeing it get little bit stronger in the currency area I think as Harold mentioned when the White Cliffs pipeline comes on, it's going to take a lot of oil out of the Denver market and make the currency market open up get stronger, I think we'll see a improvement there immediately and in time as get a jump between a direct line if you will between Cheyenne, Wyoming and Platteville, you'll see that it will get stronger. So in the next 18 months I would expect it to get quite a bit stronger.

Joseph Allman - JPMorgan

Okay, that's great. And than lastly you might have mentioned this in the start if I missed it but Bakken acreage are you seeing acreage cost decline there?

Unidentified Company Representative

No. We just we opted, we participated in Federal and State sale this past week and there was acreage there going for over $4500 an acre.

Joseph Allman - JPMorgan

Okay. And what...that's the change from say, what was that a year ago were to say.. 450 to 4500?

Harold G. Hamm - Chairman and Chief Executive Officer

Yes, compared to ...to be honest there is a huge area of Bakken there and it all depends on [ph] year you're at in relation to ongoing activity and so you're going to see it out on the extremities $250 million and as you get closer to where we are drilling wells, industry is drilling well industry if you are going to see a ramp up into that $3000 to $4500 that $4500 is on Federal leases for if you had eight, you're going to see 35 three pass 3500 notes probably the same areas with almost 316 types of lease, normal releases.

Joseph Allman - JPMorgan

Got you. Okay, very helpful. Thank you.

Operator

At this call; there are no further questions in the queue I would like to turn the call back over to Harold for closing remarks.

Harold G. Hamm - Chairman and Chief Executive Officer

Thanks again everyone for participating in our call this morning. We're looking forward to next report early next year, hope everybody has good holidays, we'll see you next year. Thank you very much.

Operator

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

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Source: Continental Resources Inc. Q3 2008 Earnings Call Transcript
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