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Continental Resources (NYSE:CLR)

Q4 2010 Earnings Call

February 24, 2011 10:00 am ET

Executives

Jeffery Hume - President and Chief Operating Officer

Harold Hamm - Executive Chairman, Chief Executive Officer and Member of Compensation Committee

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

Analysts

Leo Mariani - RBC Capital Markets, LLC

Subash Chandra - Jefferies & Company, Inc.

Gil Yang - BofA Merrill Lynch

Jason Wangler - SunTrust Robinson Humphrey, Inc.

John Freeman - Raymond James & Associates, Inc.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Eugene Lipovetsky

Noel Parks - Ladenburg Thalmann & Co. Inc.

Operator

Good day, ladies and gentlemen, and welcome to the Continental Resources Fourth Quarter 2010 Earnings Conference Call. [Operator Instructions] 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. Followed by President and COO, Jeff Hume; and CFO, John Hart and then a question-and-answer period. Additional members of management are available to answer your questions.

Now I will turn the call over to Mr. Hamm.

Harold Hamm

Good morning, everyone. Thanks for joining us on our conference call today. I'm a little bit under the weather today so I think I'll keep my comments brief and save what voice I have for Q&A. Continental finished 2010 with a strong fourth quarter production. We reported total 2010 production of 15.8 million Boe, an increase of 16% over 2009, achieving our 2010 guidance objective. We tripled our operator rig count during the past year, setting us up for continuous strong growth in 2011. Our 30% growth target remains in place for the current year. We expect to report total production of 20.6 million Boe for 2011.

On a stand-alone basis, our fourth quarter production was 48,000 Boe per day, 27% higher than production for the fourth quarter of 2009. Crude oil accounted for 73% of our production in fourth quarter, and North Dakota continued driving pretty slow oil [ph] production in the company. Continental's continued drilling success resulted in proved reserves increasing 42% for 2010. At December 31, 2010, we have proved reserves of 365 million Boe, compared with 257 million Boe at the end of 2009. I'd like to highlight three aspects of our proved reserve growth.

First, total reserve additions were 95.2 million barrels of oil equivalent, which equated to 602% of the year's production of 15.8 million Boe. The proved reserve additions were at an average F&D cost of $12.42 per Boe before revisions. After positive revisions, our F&D cost was $9.63 per Boe. Second, our year-end 2010 proved reserves were 38% proved developed producers. We have 1,282 gross, 547 net proved undeveloped locations or PUDs. About 66% of our PUDs were in the Bakken, primarily North Dakota. Of the year-end PUDs, 72% in crude oil. Third, we operate 88% of our PV-10 so we are positioned to keep growing with excellent operating discipline.

With that, I'll turn it over to John Hart for a review of our financial results.

John Hart

Thanks, Harold. We reported $221 million in EBITDAX for the fourth quarter of 2010, which represented a 40% increase over the same period of the previous year. For the year as a whole, EBITDAX totaled almost $811 million, an increase of 80% over 2009. At year-end 2010, we had $8 million in cash and $926 million in long-term debt, which gave us a net debt-to-EBITDAX ratio of 1.1, among the lowest in our peer group of E&P companies. We have excellent liquidity, as you can see, to continue supporting our growth momentum. At year-end 2010, along with our cash, we had committed available capacity of $718 million in our revolving credit facility. We currently have a total of $750 million in commitments, with a borrowing base of $1.5 billion. We believe we could increase commitments upward to the full borrowing base should we be inclined.

Finally, we reported a net loss of $45 million or $0.27 per diluted share for the fourth quarter of 2010. The loss primarily reflected a $194.4 million unrealized loss on mark to market derivative instruments. Property impairment charges. A small loss on the sale of an asset in this unrealized loss on derivatives reduced net income by $0.78 per share as we noted in our press release last evening.

We've been discussing the evolving nature of our hedging activity over the past year. We have layered in prices hedges, primarily on oil to underpin our long-term growth strategy and to provide a solid cash flow stream that will enable us to grow at an accelerated rate with what we believe will be very favorable returns.

As previously communicated, Continental has a long-term growth plan to develop our key positions in the Bakken, Woodford and Niobrara Shale Plays. Underpinning our growth plans are strong, attractively-priced hedges that support significant cash flows for use in our capital program. Let me review those.

For natural gas, we have 26 MMBTu hedged in 2011 and 3.7 MMBTu in 2012 under financial price swaps, which have average prices of $5.46 for 2011 and $5.07 for 2012. Moving over to crude oil, which obviously represents our majority product, we entered into price protection consisting of swaps and costless collars as crude oil prices have trended positively over the last year. For 2011, we had 12 million barrels under contract at an average price of $90.56. This and the following average prices represent the blended prices of our swaps and the call values of our collars.

For 2012, we have 13.5 million barrels under contract with an average price of $90.85. And for 2013, we have 13 million barrels under contract at an average price of $94.42. Our intent and our purpose in hedging is to support our growth target of tripling the size of Continental, both in terms of production and proved reserves between the year-end 2009 results and the year-end 2014 results. Our hedges should act as a strong enabler for our growth plans. For additional insight on our hedging activities, please refer to our Form 10-K which should be filed tomorrow.

With that, I'll turn it over to Jeff.

Jeffery Hume

Thanks, John. Now I'd like to review a few operating highlights from the fourth quarter and then we will have Q&A. As you saw on our press release, the North Dakota Bakken continues to drive production in proved reserve growth. Fourth quarter 2010 production in North Dakota was more than double that for the fourth quarter of 2009. We completed 40 gross operated wells, 23 net, during the fourth quarter in the North Dakota Bakken. Today, we have 21 operated rigs in North Dakota and two more in Montana. Three of the North Dakota rigs are drilling ECO-pad projects, have plans for up to five rigs drilling ECO-Pad projects later in the year. You've heard a lot from various companies lately about the constraints in North Dakota due to winter weather, truck shortages and other transportation bottlenecks and difficulty of paying service crews. Let me address each of these.

In spite of tough winter conditions, we met our guidance on production growth. This directly reflects on the quality of people we have on the ground in our 22 years of operating experience in this environment. Industry success in the play boosted total North Dakota production to a record 365,000 barrels of oil equivalent per day in November 2010. This is a 45% increase in 12 months. This kind of growth obviously increases pressure on transportation infrastructure. We are working diligently with high flying, trucking and railroad service providers to assure that, as production continues to ramp up in 2011, we're able to deliver our crude oil and natural gas efficiently in a way that maximizes its value. This has included pinching back initial production in the wells to minimize flaring [ph] while processing capacity is expanded.

To accommodate our continued rapid growth, we are working with service providers on several infrastructure projects that will be important to our success in managing oil, gas and water transportation in the Bakken. Construction is underway and the first of these projects should be completed in early April. Several other projects are slated to be completed by early summer.

The effect of these projects will be evident both in supporting our continued production growth and reducing price differentials. We're also working with trucking companies to stay ahead of increasing demand for shore hauling oil, water and rigs and other equipment. Finally, we're in great shape in terms of frac group availability in the Bakken. We have three full-time crews dedicated to Continental and two more crews that are dedicated to us on half-time basis.

Operating costs are escalating as a result of rapid growth. We've seen a 6% increase in drilling and completion costs since October 2010, due to a combination of cost pressure for service and supply and an increased number of frac stages. We remain one of the most efficient operators in the Bakken, but costs are escalating for everyone. Now let's move to the Montana side of the Bakken.

In the fourth quarter, we completed two important step-out wells in the undeveloped acreage north of Elm Coulee fairway. The Tolksdorf 1-1H and the Baxter 1-5H were completed with initial production test rates of 642 and 412 barrels of oil equivalent per day, respectively. These are encouraging, solid results and a new area for us north of Elm Coulee. Most of our 165,000 net undeveloped acres in the Montana Bakken are in this area.

Before leaving the Rockies, I'd like to note two Fort Union sand wells in the Washakie Basin. We participated with Samson as the operator on these conventional wells. The Barricade 24-36 was completed November 10, with an initial production test rate of 5 million cubic feet of gas and 198 barrels of oil per day. The Barricade 11-7 was completed on November 18, producing 4.4 million cubic feet of gas per day and 100 barrels of oil.

We have an average 22% working interest in the Barricade Unit and an average 7% working interest in the adjacent Endurance Unit. Our position provides room for 67.4 potential net wells to be completed on this acreage assuming 40-acre spacing. Two Barricade wells indicate to have average EUR of 2.65 Bcf natural gas and 58,000 barrels of oil. In Weld County, Colorado, we initiated drilling on our first Niobrara well early this month, the first to be drilled with a long lateral in the play and should have data to you by the end of May.

Now let's move to the Anadarko Woodford where we have increased our program to 10 operated rigs. In January 2011, we completed the Sprowls 1-14H well in the Southeast Cana. The Sprowls 1-14 confirmed the rich gas production and increased productivity that we saw in the Dana 1-29H, which we announced last October. The pair are 17 miles apart in Grady County and Southeast Cana. The Sprowls 1-14 flowed 2.8 million cubic feet per day and 96 barrels of oil in its first one-day test period. The salacious layer that we are now targeting certainly appears to be the right target in the Southeast Cana, yielding much stronger production rates, rich gas and high gravity oil. Even more significant was Sprowls gas's 1,300 Btus per Mcf. At a $3.95 per MMBtu residue price, the Sprowls yielded a wellhead price of $8.45 per Mcf for its January gas production.

As noted in the press release, the four wells now completed in the Southeast Cana yielded gas prices at January between $7 and $8.45 per Mcf on a wellhead Mcf basis. The high liquids content and improving productivity are the keys to the economics of these wells. The Sprowls 1-14 is the confirmation well to the Dana that we hope to see. We have approximately 86,000 net acres leased in the Southeast Cana and 83% of it is in the vicinity between the Sprowls and Dana wells. We now consider this acreage to be substantially de-risked.

Next we are drilling another test well, the Lambacas [ph] 1-11H, approximately 24 miles farther Southeast of the Dana, to test productivity in that area. We have approximately 15,000 net acres under lease in the south central part of the Grady County. We hope to have the results of this well by early May.

We're very encouraged with what we are seeing in Anadarko Woodford. In early 2010, we stepped out into the Northwest in the Anadarko Woodford in Blaine and Dewey Counties and demonstrated that the Anadarko Woodford was much larger and had more potential than just the core Canadian County part of the play. We were successful and other operators have followed. Activity has ramped up dramatically in the Northwest Cana where there are now 43 rigs drilling. Our goal now is to accelerate drilling in the Southeast Cana, developing our strategic acres position in that part of the play. In addition, we are focused on improved drilling and completion efficiencies and thus improving economics.

In total, we now have 268,000 net acres in Anadarko Woodford and we see it as the next building block in our growth plan. Finally, we announced yesterday afternoon that we have applied for permits to develop property in the Paris Basin east of the French capital in an 80/20 joint venture with Jordan Oil and Gas. We see this as a very interesting opportunity to which we could apply the technology that we've helped develop in the Bakken.

To summarize the fourth quarter in 2010, we have accomplished our goals and are on track to achieve the goals we announced for 2011 including 30% growth in production. Longer-term, we're focused on achieving our five-year goal, tripling Continental's production in proved reserves. Year one is behind us and year two looks very promising. We are focused on growth, operating discipline and building value.

With that, let's start the Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question will come from the line of Brian Lively from Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Jeff, thinking about your comments on infrastructure adds in the Williston and then overall take away, what are you expecting for oil differentials to look like in the first half of 2011?

Jeffery Hume

Right now, we're experiencing between $9 and $10 net differential back. We're moving about 20% of our gross oil production on rail at this time. We'll see that continue to grow as production in the basin grows. The pipelines are essentially filled. We have about a 25,000 barrel a day pipe increase on the Enbridge line that's going in effect this month, which will give some relief to the basin. And I believe we'll have an increase in the Butte Pipeline in a couple of months that will give some relief dependably, pretty much rail from that point on. Several companies are putting in very large rail facilities to accommodate that and we're working with all of those rail companies to make sure we have adequate space to move our oil seamlessly out. But I think that $9 to $10 range will probably what we'll be seeing.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

You think that'll hold as you continue to add to the rail core?

Jeffery Hume

Yes. Part of the rail barrels we’re able to take to Gulf Coast, we get a premium price at that area. There's currently a bit of a limitation on unloading capacity down there, but that's improving very rapidly. So we hope to take advantage of that opportunity while we can, to the extent that we can. So I think we can hold it there. We have pretty good efficiency on loading railcars now and moving the oil out and we're looking for the best markets for that oil and that's one of the advantages of the rail shipping.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

And then moving down to the Anadarko Woodford, of the -- I think it was 547 overall PUDs, how many PUDs have you actually booked to the Anadarko Woodford?

Jeffery Hume

I don't know that I have -- do you have the number, Chris?

Company Speaker

The gross number is about 80.

Jeffery Hume

About 80 gross wells.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

And that 547 was a net number, I take it?

Company Speaker

That was for all of our PUDs.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Right, but that's a net number?

Jeffery Hume

Yes.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

And then looking at the 4.6 to 6.6 EURs, and I do have the slide where you show -- you have shown in presentations the sort of average of the Woodford. But have you guys updated that type curve? And if so, what types of initial declines or first year declines or hyperbolic co-efficiency you're projecting?

Company Speaker

I think we've got about 1.8 of deep [ph] factor, initially. Initial rates in Southeast Cana is about 2.5 million a day, but Northwest is a little higher than that.

Jeffery Hume

We're looking at four to five million a day IPs in the Northwest Cana. You just have a little better perm because it's gassier. And as you go to the Southeast Cana, we're seeing heavier oil, liquid content at the well, a little bit lower IP rate. But both of them have a 1.8 D [ph] factor. So it flattens out fairly quickly.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

And the condensate yield stays relatively flat?

Jeffery Hume

Well, it varies anywhere from 10 to 200 barrels per million, depending where we're at in the play. And as the drilling progresses, we're seeing more definition on the contours of where the liquid's at. Right now, I'd say about half the play is in excess of 25 barrels of condensate per million, maybe 20% is up in that 150 to 200 barrels of condensate. So as the play progresses and we get more data points, Brian, we're going to be able to get better clarification on that.

Operator

Your next question will come from the line of John Freeman from Raymond James.

John Freeman - Raymond James & Associates, Inc.

First question on the reserves on the Bakken, what was the average EUR booking for the Bakken?

John Hart

We actually get did range depending on where we were in the basin we have, a combination of three models. But typically 430, 518.

John Freeman - Raymond James & Associates, Inc.

So it didn't change from what you all think -- like Montana is around 430, North Dakota is 518?

Jeffery Hume

That's correct. We have got a solid 518 model going in the basin, John.

John Freeman - Raymond James & Associates, Inc.

So on the EUR numbers that you all gave and regarding the Cana and your release of Northwest Cana 6.6 Bs of gas, 85,000 barrels of crude, and then the Southeast. So that basically hasn't changed from your overall assumption of like 7.1 Bs?

John Hart

That's correct.

John Freeman - Raymond James & Associates, Inc.

And then what's the latest well cost on the Cana?

John Hart

Right at $8 million.

John Freeman - Raymond James & Associates, Inc.

I know you gave Brian the gross PUDs at Cana. What was just the absolute amount of reserves for the Cana that was in your reserve number?

Jeffery Hume

John, I’m going to have to get back to that. I don't have that at my fingertips right now.

John Freeman - Raymond James & Associates, Inc.

You briefly touched on it in terms of what you all are able to do to try to address the big differential on WTI versus Louisiana light sweep [ph]. So if I understood you correctly, Jeff, the main option is you can try to rail some of it to the Gulf Coast, but it sounds like you're sort of limited on how much of that you're able to do. Can you just maybe elaborate a little bit more, how much of the volumes you're able to get kind of the Gulf Coast-type pricing on and then sort of what else you're looking at going forward?

Jeffery Hume

I believe we're getting probably 4,000 to 6,000 barrels a day to the Gulf Coast. At this time, we're working diligently to get more in that direction. As I said, as I told Brian, there's limited unloading capacity down there. So that's the limitation now. We're working diligently to get that done. I think it will grow in time. There are several avenues we're working on. I can't make any announcements now on how we can alleviate and get more oil to the Gulf. Obviously the arbitrage between pushing [ph] in the Gulf Coast makes that a high incentive for us to try to close that.

Operator

Your next question will come from the line of Leo Mariani from RBC.

Leo Mariani - RBC Capital Markets, LLC

Let's talk about well costs sort of moving up here in the Bakken. Just what are your current well costs in both North Dakota and Montana?

John Hart

We're running around $6.9 million as an average. We were running at $6.5 million. We've increased part of our stages to ramp, turn it into [ph] quite a few of our wells and 30 stages that adds about $400,000 to $600,000 per well just for the increased frac stages on part of those. When you weight it out, that's probably adding $200,000, $250,000 to your cost. The rest is just creep [ph] on costs. A little bit of slippage, it's wintertime. We got a little slippage on rig moves. Trucks can't drive as fast due to blowing snow in that. So everything just slows down. We're used to that and it's kind of built-in overall. But we've had a heavy winter up there. A lot of snow, a lot of blowing and we're getting with that. So your spud-to-spud times stretched out just a little bit in the winter, and it'll start catching up here in the next month or so and we'll be back on track.

Leo Mariani - RBC Capital Markets, LLC

Just in terms of your EURs up there, you guys are stuck with the 518, you've been moving the stages up, I guess you're now at 30. It’s obviously gone up the past couple of quarters. I think that 518 is still kind of a trailing EUR, any sense that moving to the higher number of stages is going to cause some upside to that EUR there?

Jeffery Hume

Well, it may. We're conservative on bringing numbers up. We don't want to over-hype it. One thing I'll note in our reserve report, we had quite a bit of upward revision this year and we had over 9% increase in reserve additions of 23 million barrels last year. So I think that kind of demonstrates the conservatism that we have in our overall modeling of reserves. So I think we're going to be on the conservative side of reserve adds.

Leo Mariani - RBC Capital Markets, LLC

I guess you guys talked about the tough winter as well. How much kind of production downtime you think you might have had here as we've gotten into the first quarter? I guess for a couple of months in, you think it's affected you? Is there any way you guys can roughly quantify that?

Jeffery Hume

Well, we really haven't had downtime. What we've had is a little bit of stack up of oil at the least. Just getting it to the market and a little bit of stretching of spud to spuds due to the truck availability to move rigs. But we've ramped the rigs up. Rigs, North Dakota, are over 170 total now. I believe 161 or 162 drilling in Bakken. We have eight or 10 running over in Montana. So high rig count up there. Everybody's working hard and diligently, but you just have to drive slower in the winter operations. And as I said earlier, that's going away rapidly. When we have a few days of warm weather, everything is back to rolling. So I have full confidence we'll be back on track here as winter passes.

Leo Mariani - RBC Capital Markets, LLC

I guess, do you guys still feel confident about your CapEx budget for the year at 1.36? Obviously you did talk about some costs it creates [ph]. And it sounds like your bringing some more rigs into the Anadarko Woodford.

Jeffery Hume

Yes. You know a 6% increase, if it holds through that, we had a $960 million CapEx. So $55 million, $60 million, we might see a little creep on that during the year. We might have to make an adjustment towards mid-year, but nothing real significant. We're also seeing the opportunity to pick a few rigs up in areas and we're adding those. So we'll see what that looks like at mid-year.

Operator

Your next question will come from the line of Gil Yang from Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

Could you talk about a little bit more detail about the prognosis for Richland County with the Tolksdorf and the Baxter well results? Are those IPs sort of a learning curve IPs, early in the learning curve IPs? Or do those IPs lend to the 430 EUR in the area?

Jeffery Hume

Well, I think both wells are north of the main play. We're doing our PUD development where we're seeing a strong 430s. We're seeing the wells up. These two wells are six to eight miles north of the main Field. We're looking at EUR's in the 385 to 400 range on these two wells. The cost in that area, it's shallower and is probably in that $6 million to $6.4 million range with a 24-stage frac. It's going to kick out a strong 35% rate of return with $80 to $85 wellhead costs. So pretty strong rate of return. We're excited about it because we have 165,000 acres around there. Our prognosis is to drill a few more wells up there. We currently have a Three Forks well drilling to the East of our Baxter well. It's on the eastern end of the play. We'll have it down shortly. It should have some results out here in a couple of months. Things are looking good up there. A couple of years ago we were up in that area, we were looking at 250,000 barrels per well reserve. So this is a huge increase. We've gone from 250 to 385 to 400 range. I need to get a few more wells in there to verify this. We're going to tweak our completion technology a little bit. We're talking about a little different style frac up there, cutting our costs. Our engineers have several ideas that we're going to try to cut costs with. So we're aggressively after it. I think what's exciting though is we're seeing oil out that rock, the multi-stage frac has turned it around and we have something to work with now. So we have 165,000 acres of new area to play in and we're fired up about it.

Gil Yang - BofA Merrill Lynch

And it sounds like these wells don't have that initial pop of production on the first 24-hour test, is that fair to say?

Jeffery Hume

That's fair to say but they're fairly flat. They don't have that steep decline and it's typical of what we've seen. When we moved from the Elm Cooley field to North Dakota, we had a flatter decline in our Elm Cooley core. And with North Dakota, we had those high piece [ph] and they just tail-off and that's where the multistage frac technology in the Bakken to apply. It was [ph] the North Dakota where you have much lower perm. I think we're seeing a little bit better perm in this rock than we have in a good portion of the matrix of North Dakota. So I think that's going to give us a little different shape curve and, Gil, it's going to take a few more wells for us to come up with a tight curve to fit that. But right now, that's what we're seeing on -- and what we do is early time modeling, is used in the daily information and plotting that out.

Gil Yang - BofA Merrill Lynch

Could you come down the Fort Union well that you're drilling? I guess you’re very heavily oil and what's the focus on drilling those wells at this point given the way the commodities are?

Jeffery Hume

Well, these wells have a pretty strong oil component to them. The gas is rich. We entered into an agreement with Samson several years ago, in fact, in that area. So when we picked up this acreage and it's held by those units and they continue to explore and they've just done an outstanding job working with this Fort Union. They've come up with a very, very strong frac design, very attractive economics, there's a cryogenic plant, they're delivering the gas to, and getting those liquids out of. So we're going to realize higher rates of return on these wells.

Gil Yang - BofA Merrill Lynch

Is it similar rates of return to the Cana, do you think?

John Hart

They're actually higher. At a $4 gas, we're looking about an 85% rate of return and a $3 gas is about 45%.

Jeffery Hume

Yes, Gil, these are vertical wells. So your cost is -- you're looking about $2.5 million to $3 million costs on these wells right now. And I think in time, they'll be working that cost down as they work on efficiencies. So they're still in experimental stage. They drill several wells in there. We've been in these two. We've got a third one down ready to complete. So it's an exciting area. Lots of reserve potential there. You can do the math on it.

Gil Yang - BofA Merrill Lynch

Last question is, what are the permitting criteria for Paris Basin? And what are the challenges you see to getting the permits done?

John Hart

Well, right now, the Ministry of Ecology has come out with a stay on any new permits being issued right now until they end up getting their report done, and so it's in April, they're getting a preliminary report. In June, they will have the final report, is what they say. And the expectations are that there's going to be -- we're going to be able to move ahead up there. It's just they think things are moving a little faster than they were anticipating and so they just wanted to hold things up to take another look. And so I don't see it, at this point, from what we know being a permanent hold on anything.

Gil Yang - BofA Merrill Lynch

Can you just comment on what the specific points in their report that they're going to be addressing are?

John Hart

I can't. I know they're concerned with frac-ing and resources of water, use of water, things like that. But I don't know, we’re waiting for the report to come out.

Jeffery Hume

And Gil, I think it's a comprehensive environmental assessment that the department of environment wanted to make before they issued additional permits and I guess just due course of permitting business in France and our attorney over there assures us this is a normal course of action and will be carried out.

Operator

Your next question will come from the line of Scott Wilmoth from Simmons & Company.

Scott Wilmoth

Just in the Bakken, thinking about your ECO-Pad results. Have you guys seen any interference on those wells? And what are your current thoughts on the ultimate down-spacing of the play?

John Hart

No, we haven't. We see occasionally -- when we drill two wells side by side, we'll see interference. But on the ECO-Pads, we're not seeing interference between the Three Forks and the Middle Bakken well going in one direction. We have 660 foot offset. We're not seeing any interference there. But on other patterns where we've come in and drilled wells near an existing well, we'll see some pressure spikes during the frac but we're not seeing severe drainage differences in those. So our confidence is growing on the 1,320-foot inter-well lateral spacing. There's a project, but one of our partners, they'll be drilling this year. A full set of wells on 1,320-foot inter-well spacing where we'll start getting information on that. We've said this before, it's going to be some work down the road. But looking forward, our confidence is still very high that we'll be able to put four laterals across a section in each horizon and develop that in North Dakota and without any trouble. But we're making those steps as an industry to test that, at this time. And I think for a good portion of the acreage up there, that will prove out.

Scott Wilmoth

And then just following up on the ECO-Pads, what kind of cost savings have you guys seen on those wells versus just standalone wells?

Harold Hamm

We've been right at the 10% cost savings.

Jeffery Hume

Yes. We're realizing what the engineers estimated when they planned that out originally. We are truly seeing that 10% cost savings on those and look forward to where we can get more rigs drilling the ECO-Pads. Right now, we're moving rigs in and out of ECO-Pads. I think today we're running three. We're working diligently to get our acreage commitments, our leasehold commitments acknowledged with that first well in each of the spacing unit to hold [ph] acreage. And so we're working very well, looking forward to getting on an ECO-Pad, getting bulk of the rigs on ECO-Pads, which will probably, two to three years out, we'll be seeing the switch to mostly ECO-Pad type drilling.

Harold Hamm

We do anticipate having three ECO-Pads on production within the next six weeks to traditional pads.

Scott Wilmoth

Thinking about just kind of the frac-ing and the Bakken. We heard Schlumberger announce their highway frac technology and heard an operator count their results in the Eagle Ford. Have you guys tested that in the Bakken? And if not, just talk about what else you guys are looking at in terms of completion techniques?

Harold Hamm

Yes. We have not tested it yet. We have been discussing it with Schlumberger, we're very intrigued by that and I would think that we may have something to report in the next quarter.

Scott Wilmoth

And then just jumping over to Cana Woodford. On the Analyst Day, you guys had mentioned spacing assumptions of about 160-acre spacing. Is that assumption still good and have you guys tested that?

Jeffery Hume

Well, we really haven't. We're so early, we're drilling our first well in each unit. The operators in the Cana field proper have drilled down the 80-acre spacing. There'll be releasing information on those talks that our technical folks have had with them. They're very excited about that and I think we'll just have to wait and see what comes out in the public venue to talk about it. But I feel very comfortable on the 160-acre spacing over our acreage at this time, and think it can probably potentially get down as tight as 80-acre or 100 or an 80-acre spacing.

Operator

Your next question will come from the line of Jason Wangler from SunTrust.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

In the Niobrara, you've got the first well you're drilling now and hopefully on by May. Is the plan to continue drilling the five wells back-to-back? Are you going to take a break after this first well?

Harold Hamm

Our plan would be to take a break and watch results of this first well, the Newton. The drilling on it is going very well. We anticipate being TD'd in the next 48 hours

Jeffery Hume

I was going to mention also, we've got five wells permitted out here and we're actually waiting on getting some seismic to move ahead as well as part of our waiting. And that is in progress. We've got 80 square miles of data that will be getting delivered here soon that we'll be able to use to guide our drilling.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

And on the wells, are you going to go 1280 on all of them? It sounds the opposite [ph] can make better economics? And what do you think those are going to run in terms of costs?

Jeffery Hume

We've got four 1280 and it's permitted, working right now. And then two 640s based on just ownership there...

Company Speaker

Yes, and I think the cost, we're looking at about $4.5 million.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

For the 1280?

Company Speaker

For the 1280.

Operator

Your next question will come from the line of Subash Chandra from Jefferies & Company.

Subash Chandra - Jefferies & Company, Inc.

Just an Anadarko Woodford follow-up. When you model out your returns on those wells, what kind of payout do you get?

Jeffery Hume

About a two-year payout. Two to two and a half year payout on that, Subash.

Subash Chandra - Jefferies & Company, Inc.

So the high EURs basically come from that shallow decline curve that's pretty common to the quarter, Anadarko?

Jeffery Hume

That is correct. We're seeing that across -- the salacious member just has better micro fracturing and therefore better permeability, so you get that shallower decline, we’re not going into the handle darcy rock [ph] as quickly as we are in some other areas.

Subash Chandra - Jefferies & Company, Inc.

Do you see the liquids cut kind of falling quicker and then the gas rising to the life of the well?

Jeffery Hume

We haven't seen that yet. We're pretty much holding that liquid gas ratio in those areas which is somewhat surprising to me. I thought we'd see it starting to fall off but I think we're still early enough in most of these wells’ life is above bubble point, under bottom hole conditions. So the liquid is moving with the gas. We haven't had any free gas breaking out of the formation yet, and so it's looking pretty strong. I think we're going to hold up fairly well. I think that’s just a testament to the superior permeability of this resource play.

Subash Chandra - Jefferies & Company, Inc.

In terms of price sensitivity, if we were to compare it to the Bakken, holding gas stay flat at current prices for whatever, on what oil price is this -- do the economics here become marginal in the Anadarko?

Jeffery Hume

Oil price?

Subash Chandra - Jefferies & Company, Inc.

Yes.

Jeffery Hume

I don't know. I think we're anything above $50. We're going to have some decent now -- comparing it to the Bakken to Bakken currently have stronger rates of return by about 10% to 15%. We're working on both of these plays getting costs down and got a few techniques to -- as everyone is, to drill the wells, drill and complete the wells at less cost and then at the same time to extract more reserves out of them. So they're in competition in-house. And right now the Bakken's got the upper hand, but I think the Anadarko team is going to make some pretty strong strides this next year. We're very early in the play, just now making strides in improving our drilling time to working with vendors on technology and just methodologies of completing the wells. I think it's going to improve over time.

Subash Chandra - Jefferies & Company, Inc.

The 10 rigs you're running, is it safe to say that that's more than what you needed for lease retention?

Jeffery Hume

At this time, we're going to be in future years climbing that rig count. We've got a internal plan to grow that. What we want to do, Subash, is keep the rig count fairly low until we climb the learning curve and also to get a good feel on where this high liquids portion of the field is, identify what our economics are across the field and the bring in additional rigs. I think you'll see us ramping. The plan is to ramp rig count up in 2012 and beyond to cover that, but we can easily handle that. We can easily maintain our acreage.

Subash Chandra - Jefferies & Company, Inc.

As I look at sort of the modeling the economics your [ph] Anadarko -- let's say 1,300 Btu gas, how much of that is paid as a fee to the midstream operator?

Jeffery Hume

We don't have any -- in the Southeast Cana, I don't have any long-term contracts at this time. We're going pretty much well to well. But we're going to retain the bulk of the flow stream. And most contracts out there now with various midstream companies you're paying for gathering and compression fee and getting a fairly high percent of proceed. I just can't say what that percent is but it's fairly high. We're going to keep a healthy portion of that.

Subash Chandra - Jefferies & Company, Inc.

So the wells you have now, are they being sent for processing or are they being blended with drier gas and sitting pipeline sites?

Jeffery Hume

They're being processed. But my point is, they're being sold on a well-by-well basis. I haven't entered into a contract for a large area yet, so I can't quote a contract term. But we're getting the bulk of the liquids out of that. All of our gas is going to plants. They're cryogenic and knocking all the liquid out as percent of proceeds. So we're harvesting all the liquid out of the gas.

Operator

Your next question will come from the line of Noel Parks from Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann & Co. Inc.

The exploration expense item in the quarter was higher than it's been in a while. I was just wondering if that was dry holes or seismic or what that was made up of?

Harold Hamm

Noel, we did have a higher level of seismic and prospecting costs due to the expansion of our exploration program in the quarter. We were about $2 million, $2.5 million higher in that regard for the quarter. And then for the year, obviously we've been stepping up those activities also.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Will we expect to see something -- similar levels going forward for the rest of the year?

Harold Hamm

We've got an active exploration program, as Jack spoke we're shooting a seismic in the Niobrara and there'll be other areas. So that ebbs and flows depending on the stage that we're in, in the program.

Jeffery Hume

I would say '11 will be somewhat similar to '10 in that regard.

Noel Parks - Ladenburg Thalmann & Co. Inc.

And one other thing, did you give the deferred taxes versus the cash taxes number for the quarter?

Jeffery Hume

Not for the quarter. We've given it in our guidance before and it's in line with our guidance, which is kind of in the 90-10, 95-5 range.

Noel Parks - Ladenburg Thalmann & Co. Inc.

I guess turning to the Bakken and thinking about one of those last big slugs of property acquisitions you did, I think about this time a year ago, if memory serves me. I think it was about 70,000 acres you got maybe in the state acreage sale, is that right?

Jeffery Hume

We did a combination of state acreage sales and some acquisitions from several other operators. And most of that was West of the Nesson Anticline on both sides of the Missouri river, and that's proving up to be just excellent acreage.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Since obviously you don't have lease expirations bearing down on you right there you've been able to do a good bit of de-risking in that part of the acreage?

Jeffery Hume

Yes, we have. We are currently doing de-risking, as I said, it's proving up to be very strong area for us. We're running approximately of our 23 rigs across the play, approximately 15 of those are working everyday on acreage to hold acreage. So we'll be working diligently to do that. We have a plan, we have a comprehensive plan. We've got every spacing unit identified, when the exploration is and we manage that and we will not lose any acreage.

Noel Parks - Ladenburg Thalmann & Co. Inc.

For that area, can you just give a sense on what you've seen as far as the prospectivity of the Three Forks versus the Bakken. Is one looking better than the other? I know it's a big area but just in general terms.

Jeffery Hume

Both of those are looking -- still fairly early to do a comparison. The data set is just too small to say one is better than the other. We've seen very strong results out of both horizons through the area and that is the good news. We have both horizons -- are exist through that area. Ourselves and other operators are testing both horizons. I think as we get a data set, we'll be able to see what that is. We're seeing strong results in there and still a little early though to be talking about one over the other, but by and large, it just spins geographically where you're at, which one's stronger. It's just the way the rocks have been laid down.

Operator

[Operator Instructions] Your next question is a follow-up from the line of Gil Yang from Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

I just wanted to follow up regarding the ECO-Pad, the cost savings. Is that 10% cost savings embedded within your $6.5 million or $6.9 million average currently or is that on...

John Hart

No, Gil. We specifically pulled those out because we want to get a more represented cost. So you can back off that 10% off of that $6.9 million.

Gil Yang - BofA Merrill Lynch

So the nine ECO-Pad wells cost $6.9 million. ECO-Pads cost about $6.2 million, $6.3 million?

John Hart

That's right. That'll be in the range.

Operator

Your next question will come from the line of Eugene Lipovetsky from Zimmer Lucas.

Eugene Lipovetsky

First, can you talk about how much it cost you to get into this joint venture with Jordan Oil in the Paris Basin?

Jeffery Hume

Nothing yet.

Eugene Lipovetsky

So there's no upfront cash consideration to get into this potential JV?

Jeffery Hume

No. We're in there just as joint partners in that.

Eugene Lipovetsky

My next question is about Montana wells. What was the percent of the gas content in those wells?

Harold Hamm

Typically, the gas in that area is in the 600 to 700 GOR. So on a percentage basis, you're probably 10%.

Eugene Lipovetsky

And one thing I would just like to make sure I heard correctly, I think it was Jeff who answered this question, I think originally posted by Subash. But I just wanted to make sure I heard you correctly. The long lateral Niobrara wells, did you say that they're going to if you [ph] for about $4.5 million?

Jeffery Hume

Actually, I misspoke. I apologize. The 640 in our model isn't the $4.5 million, and we're looking at $6 million in the longer laterals.

Eugene Lipovetsky

One last question do you have the current rates for the Dana well in terms of what's the current gas and the current liquids rate out of that one well?

Jeffery Hume

The current rate on the Dana well is about 2.1 million a day. And I believe it's in the 50 barrel a day range on oil.

Operator

There are no further questions. That does conclude today's conference. Thank you for your participation. You may now disconnect. Have a great day.

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