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Continental Resources, Inc. (NYSE:CLR)

Q1 2010 Earnings Call

May 6, 2010 10:00 AM ET

Executives

Harold Hamm - Chairman & CEO

Jeff Hume - President & COO

John Hart - CFO

Jack Stark - SVP of Exploration

Tom Luttrell - SVP of Land

Rick Muncrief - SVP of Operations

Analysts

Mike Jacobs - Tudor Pickering Holt

Scott Wilmot - Simmons & Co.

Noel Parks - Ladenburg Thalmann

Subhash Chandra - Jefferies

Sven Del Pozzo - C.K. Cooper

Gil Yang - Bank of America

Chris Pikul - Morgan Keegan

Mitch Wurschmidt - KeyBanc

John Freeman - Raymond James

TJ Schultz - RBC Capital

Bob Carlson - Janney Montgomery Scott

Gail Nicholson - Pritchard Capital Market

Brian Kuzma - Weiss Multi-Strategy

Operator

Good day, ladies and gentlemen and welcome to the Continental Resources’ first quarter 2010 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 the company’s first 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.

Finally, in the question-and-answer period, several additional members of management will be available to answer questions, including John Hart, Chief Financial Officer; and Jack Stark, Senior Vice President, Explorations; Tom Luttrell, Senior Vice President, Land.

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

Harold Hamm

Good morning, everyone Thank you for joining us today. We’ve had an excellent start with first quarter of 2010. The baseball season is here, that remains me of my days of pitcher on the baseball diamond. So here today, I’m going to show you three keys basis, we’ve got carried in 2010. Let me toss out a new ball and talk about a next home run for shareholders.

Alright, now on first base, we’ve got the oil-rich inventory, which is a right platform at the right time. Today, everyone wants to become an old man and movement is second base. We have superior economics with the foundation of the lowest cost in our industry and third base, we have more than 770,000 Bakken acres sounds the best leases and new study show they’re even better than previously assessed, better than previously thought, better than previously believed and we’re throwing on a new ball today in the form of a 20% higher AUR model for our Bakken wells. For me next on run will be the ramp up in our drilling activity and accelerate growth in the future for Continental.

Let’s start talking about first phase, so oil-rich inventory. A famous author once said, the amortization is the most sincere form of flattery. Today many US E&P companies have announced plan to diversify natural to oil recently, what we did that 22 years ago. In our first quarter production was 76% crude oil, all organic growth.

Our North Dakota production was two times, that wasn’t first quarter of 2009 and total Bakken, March exit rate was 16,150 barrels of oil equivalent per day. Our total production in March exit rate for the company was 40,503 barrels. Our average crude oil price for this period was $71.41 per barrel, two times what it was of course first quarter of 2009 during the economic downturn.

A differential that we’ve experienced was $7.42 per barrel, and this was left in the guidance of $8 to $10 average for the year that were given and we expect further reductions in the future where the own rig commitment Bank of Montana by transferring a pipeline on their Keystone XL.

I think in head is up to Montana’s Governor, Brian Schweitzer, who worked diligently with me and others and transferring a pipeline to make this possible. Additional capacity with potential could be coming on ramp in North Dakota, Governor Hoeven, know the North Dakota officials working with TransCanada there.

This could create a lot of jobs are apportioned and then more investment for Montana and North Dakota and they have great benefit for local producers as a production continues to climb in those States. Of course our total oil and natural gas sales of $217 million is more than twice what it was first quarter 2009.

Next let’s move onto second base. The period of economics of crude oil, especially with our low operating cost, gave us a three times increase in EBITDAX in first quarter 2010 of a $178 million. Our production expense was $6.46 per Boe versus $7.24 in first quarter of ’09 at the 11% savings year-over-year and I think it’s the lowest in the industry, if not it’s very close to the lowest. So we had a net income of $73 million, reporting $0.03 per diluted share versus a net loss of $27 million first quarter of ’09.

Third base, our tremendous lease positions in drilling inventory. 773,000 net Bakken areas adding to oil-rich inventory. To put this in perspective, just 18 months ago September, 2008, we had 577,000 net acres in Bakken, just a 34% increase over that period. So while everybody else was said to increase still back in 2009 in a downturn, we were out there busily picking up additional acreage, and as evidenced by yesterday’s State sale, these are very valuable leases today.

Let’s talk a little about our oil exploration capability and the strategic value of it, we continued to build an expand position emerging all place in onshore were lower 48 US. You heard about the Woodford, that we announced last quarter and we have others that say, we worked on diligently.

Given what toss out a new ball in this game and that has to do with the URs. We’ve increased the URs at the company to 518,000 Boe, this is a 20% improvement in just six months, Bakken is still getting better folks. It is based on higher initial production in North Dakota wells, and our experience there and stronger performance over 30, 60, and 90 days.

First quarter 2009 wells, first 90 days production averages just over 200 barrels a day. Fourth quarter 2009 wells, first 90 days production averaged almost 600 barrels per day or three times. This doesn’t account the wells Bakken in first quarter 2010, we don’t have complete 60, 90 day data for those and then there is further support from the new North Dakota Industrial Commission Study on the Bakken.

As a Great Plains Energy Explorers and Bizmark in November 2009, I stated that 8 billion barrels or mortgage recovered with advancement in technology, the additional Three Forks and expanded geological area at the Bakken. Of course USGS as you remember gave 3 billion to 4.3 billion barrel recovered with current technology as April 2008.

The recent NDIC study progressed April 29, gave a 2 billion barrels potential just for Three Forks in North Dakota, almost entirely added into this USGS number. Of course this confirms the Continental testing of the Three Forks’ potentials in 2008, as construed college and mortgage city Minnesota recently, are stated that the total Bakken system, I believe as two times the potential of the USGS report from April 2008. That USGS study was based on results only through June 2007 and of course, if you recall back at that time I was very early in the technological cycle of the Bakken.

Let’s just talk about the homerun and what’s to come in our future; basically, as more production growth. We’ve had excellent first quarter 2010 production performance and I ramp here at Continental and the drilling program continues.

Now we operate 23 rigs under contract with 15 of those in the Bakken. By the end of May, we expect to add two more in Bakken. We have a clear focus in oil and liquids price, and very important total production volume increased related to this build up and Continental rigs are still coming in future. So you can expect to see a surge in second half of 2010 and 2011’s production rates from Continental.

Continental have a tremendous oil concentrated platform for growth, we’re focused on realizing in various tremendous assets, especially our huge position in Bakken, 88% of our drilling CapEx are focused on crude oil at NGL concentrated plays, Bakken had a merging of plays. We’re going to maintain a strong balance sheet and layer in hedges to underpin our drilling program as we go forward. We have good jump down on this thing and we’re looking forward to this year’s schedule that we got a strong line up for the next several years.

With that, I’ll turn the call over to Jeff Hume.

Jeff Hume

Thank you, Harold. It looks like embedding cleanup new schemes, so we’re all drilled down a bit further in the Bakken, the Red River and the Woodford plays. Like we’ve noted, the Bakken contributed 40% of our first quarter 2010 production and for the first time surpassed the Red River units, which accounted for 36% of total production. North Dakota Bakken was 26% and the Montana Bakken was 14% of total production for the quarter.

In addition, note that North Dakota Bakken has more than doubled year-over-year, while the Montana Bakken dropped from 6,100 to 5,300 barrels of oil per day due to limited drilling activity during the past 12 months. During the first quarter, Continental participated in completing 36 wells, 10.6 net in the North Dakota Bakken with an average 24 IP of 1,410 barrels of oil equivalent per day.

Now, I’d like review seven of our first quarter company operated completions beginning on the Nesson Anticline. Number one, the Hawkinson 1-22H in Dunn County IPed at 2,338 barrels of oil equivalent; number two, the Clover 1-3 in Dunn County IPed at 897 Boe; number three, the Kummer 1-31 in McKenzie County, IPed at 715 Boe; number four, the Muri 1-27 in McKenzie County IPed at 1277 Boe; number five, the Bice 2-29 in Dunn County IPed at 1429 Boe.

We want to make it clear about the significance of the Bice No. 2, what we’re speaking on it. This was a Middle Bakken completion and 660 foot offset to the Bice No. 1 Three Forks completion. The Bice No. 2 had version pressure and proved to be unaffected by production from Bice No. 1, which had produced since May of 2008.

Now let me give you a glance results from two wells on our new exploratory area in Western Williams County that everyone is interested in, which we call Round Prairie. No. 6 is our Obert 1-13, at 896 barrels of oil equivalent. I would like to note that after the fourth quarter conference call, some investors comment if they do catch the Obert versus the first Three Forks test in Western Williams Country. We are very pleased with results and the potential for dual reservoir well in this area, where there is only 38 feet of separation between the top of the Middle Bakken and the top of the Three Forks.

No. 7, our Stedman 1-24, I repeat it 979 barrels of oil equivalent. I like to make it clear, that the Stedman is the Middle Bakken well that offsets over and was completed in early April. Its early production curve is declining much more slowly than the over and appears to be a very strong well.

So to give you a total picture of activity, today we have 15 active operated rigs in Bakken. We’ve planned to move two new rigs into the play by next month. One rig is drilling in Montana, and the remaining 14 are in the North Dakota Bakken. Two of these are walking rigs doing equal flat drilling on the Nesson Anticline and these projects were progressing nicely.

We have two operated rigs drilling and one new rig moving into the Round Prairie Prospect. As I mentioned earlier, Round Prairie is far of Western Williams County where we announced over Three Forks test and the Stedman Middle Bakken test. We are drilling both Middle Bakken and Three Forks test in the Round Prairie area.

We will soon be moving our rig from the Nesson Anticline to the Williston Basin or the Williston Prospect, which is located on the west side of the Nesson Anticline in Williams and McKenzie Counties. This rig will begin the lineation of the Middle Bakken and Three Forks jumps in this area.

Remaining eight Dakota operated rigs are working up and down in the Nesson Anticline and we are currently moving in a ninth rig to that area. I noted earlier, we’ll be moving into two operated rigs by next month. These will be EcoFair projects in the [knurs] area, which is at the north end of the Nesson Anticline.

Our biggest change in the first quarter operating approach in North Dakota, was a decision in mid-March to track with a minimum of 24 stages per well, based upon the improving results we were experiencing. We planned to test several wells with even more stages, maybe 34 stages in the future. To further define the economic limit of higher frac stage density in different areas of the field.

Service costs are beginning to rise due to the increasing activity, where I can tell you, we are currently holding our average drilling completion cost below $6 million per well with 24 stage fracs. However, we are hearing the pressures quite high in some of the smaller operators. As previously mentioned, we currently control over 773,000 net acres in Bakken play a 20% increase since January, quarter-over-quarter gain close to 128,000 acres.

Now, let’s look at our activity in the Oklahoma Woodford, in Anadarko Basin, we have recently increased to three rigs drilling in the Northwest Cana part of the play, which is Dewey and Blaine County. Our 2010 plan involves continued field delineation for productivity and liquids yield across the entire acreage holdings of the play.

Key current activity is first our Doris 1-25 oil in Dewey County, where we just wrapped up drilling and that well is scheduled for frac next week. This well is located five miles out of the Brown 1-2, which has had excellent performance thus far. Second, our Ballard 1-17 in Southern Grady County near the McCalla well that we announced close to a year ago is currently flowing 130 barrels of oil and 650 Mcf of gas per day.

We are very encouraged with this area due the high 200 barrels per million yield and extremely rich NGO content. This past month, we’ve received close to $9 in Mcf for gas in that well. We believe, that well performance can improve significantly in this area, to prove that we planned a drill an offset well to the Ballard beginning late in the second quarter and third, we currently have 205,000 net acres at Anadarko, Woodford which is continuing to grow. In the Arkoma basin on the East side of the state, we continued to offer one rig fulfilling delineation work in the East McAlester area. Our non-operated activity continues at a high pace predominantly with 80 acre development.

Now, quick snapshot of the Red River Units; in March of 2010, our production averaged 14,580 barrels of oil equivalent per day and is now moving fast 15,000 barrels to a projected target of 15,500 barrels. We currently have three rigs operating in the units and continue to convert producers to injectors as we continue to increase density wells development drilling. In closing our key goal for the rest of 2010 is to remain heavily focused on our Bakken asset, again I want to stress 88% of our 2010 drilling CapEx will be deployed on oil and NGO rich plays.

I will now open the call to any questions.

Question-and-Answer Session

Operator

Thank you, sir. (Operator Instructions) Gentleman, your first question comes from the line of Mike Jacobs with Tudor Pickering Holt; please proceed.

Mike Jacobs - Tudor Pickering Holt

Congrats on the improvement in results it’s like a combination of high batting average and slugging percentage. I want to get a little bit in the leads on the Williston, and I’ll try not to ask anything way out in left field. Since you’ve talked about the Bakken for its Fault Zone in the past and your press release suggests that, you’ve been adding acreage in kind of what looks like the golden triangle on that map, if you would at the southeast of the zone. What are you seeing there, and can you specifically discuss how the perm and porosity changes as you move west of the Nesson into the portions of Roosevelt County?

Jeff Hume

I’ll take a shot added in Jack, you fall up here is you see that, I think generally what we’ve seen as we’ve gone less there, a lot of people realized that there was a Prairie Rock west of the Nesson Anticline and I think that’s the case that the newer technologies of five times chunks of that rock and fracture stimulation in several stages really have opened the door to it from some of the earlier test that was Tracey and others made there back in 2007.

So it has open the door to it and we’ve realized that early on and started releasing heavily back there year and a half, two years ago and a fill net acreage in and out there and so it has become very perspective even in the Prairie Rock area. It’s all saturated and certainly going to be productive toward the [Bakken broad]. So, Jack anything there to add?

Jack Stark

No.

Mike Jacobs - Tudor Pickering Holt

Just moving a little bit further east you talked about the Steadman well performance versus the Obert well. How do you think about recoveries for the Three Forks versus the Middle Bakken, west of the Nesson, and how did that change when you move even further west of Round Prairie?

Harold Hamm

We’re seeing very consistent results in both of those and right now that the data set west of Nesson Anticline is pretty low on the Three Forks, couple of operators in Three Forks well, but there’s just not many. We took the initiative to drill well in far western Williams County, knowing that we had a thin section there, and we need prove what it will do.

It had great shows in it. It’s producing well and I think we maybe able to produce even below that 50 per separation and have dual drainage in those areas, but it’s going to take some time Mike, before we can really give a definitive answer on that, but at this time, I’m very optimistic about having the dual reservoir concept as far as the Montana State Line.

Mike Jacobs - Tudor Pickering Holt

If I could just ask a couple of questions on design and completion, were you using sliding sleeves or perf and plug on the 20 stage completions?

Harold Hamm

We’re using perf and plug on everything we’re doing.

Mike Jacobs - Tudor Pickering Holt

The ASE that you cited for the 24 stage completion, it's a low number and I think part of that, correct me if I'm wrong, is that you're using less ceramic proppants and then what other operators are using. Can you talk about the evolution of your completion cocktail as you move across the basin, and how is that going to change as you move to higher order completions?

Jeff Hume

We’re using approximately 35% to 40% of our profit is ceramic. We’re tailing most of our stage with ceramic. I think every stage we’re pumping now is tail with predominantly ceramic. We’re having very good results with that mix. We feel like it’s a very economic mix, we’re getting great performance with that, the profit staying in place.

Now the cost, as we move across in the areas that are shallower such as to the north, obviously cost, and cost are slightly lower due to the shallower debts and if we move deeper into the basin, we have a drill a little deeper, slightly more drilling time and the frac pressure is slightly higher as you’re paying higher frac deal for hydraulic horsepower. Other than that, it’s pretty fairly consistent cost out there, other than those two changes in parameters for the depth and frac gradient, have more casing cost and what their higher frac gradient have a little studier casing design. For the most parts, it’s how we’re seeing it and designing it.

Mike Jacobs - Tudor Pickering Holt

Last question, I'll jump off. What de-factor and terminal decline rate, are you assuming in that net 518,000 Boe number on average?

Jeff Hume

No, I don’t have that on top of my head, but I can sure get that to you.

Operator

Gentlemen, your next question will come from the line of Scott Wilmot with Simmons & Co.; please proceed.

Scott Wilmot - Simmons & Co.

Just touching back on well costs, can you guys update us on your expectations for the differences in wells that you’re going to drill on ECO-Pads versus standalone wells?

Jeff Hume

No, we started up thinking that it was going to be 10% at least savings and it seems to be better for better, Rick Muncrief is here, our Operations’ Superintend or VP, what you think Rick.

Rick Muncrief

I think it’s still consistent with what the guidance we gave earlier 10% savings. We have a two ECO-Pad rigs running currently, it’s impressing nicely and we’re hopefully so no change what we said earlier.

Scott Wilmot - Simmons & Co.

When can we expect our first result out of the ECO-Pads?

Jeff Hume

On owned well we’ve got the first lateral drill. We’re actually screwing the second lateral. So you probably 45 days out.

Scott Wilmot - Simmons & Co.

Then just you mentioned the tightening service cost environment. Can you quantify any expectations for the back half of the year, or is it more looking like a 2011 event where you start to see some pressure?

Jeff Hume

We’re just seeing mile pressure right now and this as I mentioned in my delivery we are hearing from a lot of smaller operators of fairly significant pressure put on them to the point of calls that just not return on the call over equipment. I think one of our advantages is the size and number of rigs in activity. The service companies are cater into ourselves and other larger operators just do the mass, but I’m sure there will be some pressure I’m not giving any guidance on what that would be, because it’s hard to predict what that would be, but I can manage there will be some pressure on that as we continued to grow.

As you know steel has going up every month this year, so as we ramp up activity and the steel mills get back to operation, we’re going to have pressure on steel. It’s going to be pressure on labor, right now everyone that can work is working in Western North Dakota, Eastern Montana, there are 100 of folks, lot of people are I think brought into work. So that’s were most of the pressure is going to be outside of that, I don’t see a significant increase other than taking care of labor demands.

Scott Wilmot - Simmons & Co.

Then jumping over to the Cana Woodford, it seems like leasing activity and drilling activity has moved towards your Northwestern acreage. Can you guys comment on your plans for the back half of the year and if you guys are still looking at adding acreage there?

Jeff Hume

We are still adding acreage in that area. Right now the three rigs we have running are in the area to the Northwest of Cana and our plan is to drill somewhat in our checkerboard across that area to lineate areas of productivity and high liquid yield and doing that, we’re going to identify, where we have the highest rates return today with disparity between oil and gas price and then, next year we’ll be ramping the rig count up in those areas and accelerating in this place. So that’s our plan for second half of 2010.

Scott Wilmot - Simmons & Co.

Can you just remind of current well cost in that play?

Jeff Hume

We’re running close to $6 million, $6.5 million in that area.

Operator

Gentlemen, your next question comes from the line of Noel Parks with Ladenburg Thalmann; please proceed.

Noel Parks - Ladenburg Thalmann

Just a couple of things, I just might have missed this, but talking about the wells that you drilled, there was one mentioned in the press release, the Willie 1-25 at about 648 barrels that I think was right on the anticline. Was that roughly inline with your expectations?

Jeff Hume

Yes, the Willie is in the southern part of our Norse project, and we do see the ranges of outcomes up in that area, when that 600 barrel a day up to some of these wells up there, we’ve seen operates in 2,000 barrels a day on our 24 hour test. So, we feel that it’s on southern end of our Norse project. We do see a little bit of diminishing in outcome there, but geological across the play and across just the Norse project in south, you see these vertical outcomes due to geology.

Noel Parks - Ladenburg Thalmann

There was not a huge number, but there wasn’t an impairment charge this quarter. Can you just tell me what was behind that?

John Hart

Certainly, there were two components. Really the first component would be just older wells passing their economic limit. There were three smaller wells and total up to approximately $1 million that past that economic limit and were compared during the quarter. The remainder, we amortize our leasehold over the later delays we look at it obviously, some acreage proves out and other doesn’t, so we make estimates on that we amortize it over the delays and we adjust that quarterly, so the remaining $14 million or so was related to just normal lease amortizations.

Noel Parks - Ladenburg Thalmann

Just a housekeeping item, what was the deferred tax amount in the quarter?

John Hart

I’ll get that percentage for you and we’ll circle back with you on that, higher that the cash components relatively low, but I’ll get that and we’ll circle back.

Operator

Gentlemen, your next question will come from the line of Subhash Chandra with Jefferies; please proceed.

Subhash Chandra - Jefferies

To kind of get back to gas for a second, two things one is, in the Haynesville, you built position there. The market soared, the market came back down. There is about a million acres that will turn over in the next year and a half. So first question is, do you think it makes some sense to commit to that piece of business now with all the lease expiries that are said to take place, and second, I only ask this because you have a presence in southern Michigan, but are you aware of or participating in that huge land grab in northern Michigan around Traverse City. My final question I guess is, did you participate in the end of state lease sale, and any comment there I mean, who's Boston Energy? So I’ll leave it at that?

Jeff Hume

This is Jeff. I’ll take off with the Haynesville. The acreage we have in the Haynesville, we have another year plus on the leases and we have the right to extent those for two years and today, we have higher rates return in other areas. So we’re differing drilling in that area at this time and we’re moving spec capital that we had plan into the Red River units. So that’s why we’re up to three rigs there. So it’s very question.

We have the option to either develop that acreage later or to market that and we’re considering those opportunities. As far as the Michigan, Southern Michigan we are very active in Southern Michigan with the Black Warrior Basin and I’m not aware of new activity to Norse. So we need some information from you on that, I guess to comment on that.

Jeff Hume

Yes, it’s a Utica, against a huge play on Utica Shale well. So I think they had a couple of days ago, lease sale about $180 million as what they bagged, I think it might be 1500 acre, which is pretty unheard of that, but it is guess.

John Hart

Yes, we were aware of that and because it was gas, we had people there and then those leases went extremely high like you said. So we think we’ve got better prices to go with the money and we were doing that. Like Jeff said, it was Trenton/Black River area, we were proceeding down there, that’s we market it’s treated us very well and we’re going forward with that, but the land grab up there in the Conwood we may not make that.

Subhash Chandra - Jefferies

So then in North Dakota lease sales specifically, did you participate or it looks like, that mean whatever it was 4500 acres McKenzie. I haven't looked at the map, but was that largely west of the anticline type setting.

Harold Hamm

It was and I can’t just tell you that very quick, that there’s nothing going on and we’re not in on. That’s the way they work, we definitely were there to table and we bought our share. As I mentioned earlier, these are very valuable leases, this thing is mostly leased up. Now the acreage is past tense, and so a lot of people I think, view this is one of loss sales out there and which extremely pricy, 4500 we saw leases sold for 7500 so per acre. These state leases five years a good term modem. So I think that’s why people were paying on up for those.

Subhash Chandra - Jefferies

Harold, do you do any, I know you do some of the big picture stuff for North Dakota as well as for Oklahoma, when you talked to various groups, but have you sort of come up with any estimates on what Bakken production might be in the next several years?

Harold Hamm

As far as daily production up there, we have Subhash and this week we heard from IHS at the convention out there that they expected that maybe production to go 900,000 to a million barrels a day. There’s about twice what Lynn Helms or North Dakota is predicated for North Dakota, of course we had Montana to that and then his number might have been for inclusive of the Bakken in Canada, they’re about 60,000 barrels a day in Saskatchewan.

I don’t think that the numbers out of question, that’s going to be down the road, this thing is going to be gone on for 10 to 20 years; Huge Play then, we’re glad to have 90 million acreages in it. So we work with some of those numbers and I wouldn’t discount what he was putting forth.

Operator

Gentlemen, your next question will come from the line of Sven Del Pozzo of C.K. Cooper; please proceed.

Sven Del Pozzo - C.K. Cooper

Of the 128,000 net acres that you added in the Bakken that you mentioned on the call, I have some impression that some of that is on the border between Williams and McKenzie County kind of in the center of McKenzie County that that’s where you had been accumulating acreage with, but I don’t know how much of the 128,000 or what would you be willing to tell us in terms of where are you leasing?

Jeff Hume

Sven, most of the acreage has been, just as you described is east and west the longer river between Williams, McKenzie County, but quite a bit of the results were up and down the Nesson Anticline filling in just acreages that was open there. So those are the two main areas where the acreage was at. We also filled in at around the Round Pierre area right on Roosevelt County, Montana, Williams County area were drilling have three rigs running today and so, this year we’ve added around 90,000 acres in North Dakota and about 38,000 in Montana. So I give you kind of a little bit better feel for how it spread out there.

Sven Del Pozzo - C.K. Cooper

Of those wells that you mentioned in your press release, there are one’s in North Dakota. Were those all on 1280 spacing?

Jeff Hume

They are.

Sven Del Pozzo - C.K. Cooper

Then just the modeling question for the Woodford, on your Woodford acreage do you enjoy that low production taxes until the wells each payout and I think on the order 1% percent before it jumps to seven once the wells reach payout?

Jeff Hume

That is correct. It’s 48 months or well payout. This is the current tax on those, 1% and it goes back to the 7% back.

Sven Del Pozzo - C.K. Cooper

Is that for all, is that would apply to all of your acreage in --?

Jeff Hume

All horizontal wells.

Sven Del Pozzo - C.K. Cooper

Would you be willing to sell any of that acreage at the right price giving, to say you had a major come in and European major or something that needs some growth?

Jeff Hume

Well, I’d never say never, it depends what they do. We’re still accumulating acreage there and as we delineate the field and learn what our true economics are for the different areas. As I’ve mentioned before the Oklahoma Woodford is much like the Eagle Ford, where you go from a dry gas window down to a liquids rich to almost in oil zone to the north and so as you move up dip and when you’re seeing both [Devon and Simerex] and Continental doing the same thing along their trend to delineate that band to improve the economics with the disparity in product prices we have between gas and oil now. So, it’s going to be a very strong play, that delineation will be probably pretty well defined by the end of this year with the drilling that’s going on. The acreage therefore is becoming more and more valuable as we unlock its potential.

Sven Del Pozzo - C.K. Cooper

Lastly, what would you suggest would be operating cost that I can use in modeling the Anadarko Woodford?

Jeff Hume

We’d probably have $5,000 a month operating costs, if you want to take it to per Mcf equivalent or something described, look at the decline curve, average that out for each quarter of the year we’re looking at.

Operator

Your next question comes from the line of Gil Yang with Bank of America.

Gil Yang - Bank of America

In the acreages you’re picking up in sort of a more core areas in Bakken. Are you able to do that, are you a beneficiary of the tightness in the service market where smaller operators are sort of throwing their hands up in sort of offering up their acreage for sale or is that not a factor or is it a factor yet to come?

Harold Hamm

No, that is a factor and it is factor yet to come as we forward. We’ve had a pretty consistent operation up there for a lot of years and a lot of the contractors looked us as somebody is going to be around and good times and bad. So smaller operators that speculate on acreage looking for good operator, we’ve been approached several times and made deals and just recently and we expect calls pickup, we’re asking the calls and we’re on the top too and we go forward, make a deal with them a win-win situation for everybody and so it’s a good question.

Gil Yang - Bank of America

Can you comment at all on the terms of these new leases in terms of royalties and maybe rough acreage costs?

Harold Hamm

At least recently lease to State leases that’s six royalty and stretch where that’s and five year term.

Gil Yang - Bank of America

Then, no comment on the private market land though?

Harold Hamm

No, we’re seeing it’s too competitive.

Gil Yang - Bank of America

For the segment in the Obert wells that you drilled, is there any indication if they’re interfering with each other or are they pretty much independent with each other?

Jeff Hume

They’re totally independent with each other different spacing units we would expect to have any interferences cause way out to one and other.

Gil Yang - Bank of America

Did you mention in answer to another question earlier that you were thinking of producing both the Middle Bakken and the Three Forks out of one well?

Jeff Hume

No, we’ve not gone to that. Our development plan right now is when we go to full development is to have the ECO-Pad design where we’ll have separate well bores in the Three Forks and separate well in the Middle Bakken. One other operator is testing that concept now and we’ll see how that works. It’s quite difficult mechanically, there’s a quite a bit of mechanical risk, hopefully, in the future that we’ll be able to be done economically for the first time. I’m able to develop the way I’m doing much less it’s basically than what they’re doing.

Gil Yang - Bank of America

A question for Harold, you’ve been in this business for a long time and build a very successful company and you commented in your opening remarks, I think that you’ve been looking at oil development for many, many years. Is your view that the gas and oil disparity that we see today is here to stay for the next 20 years or, how can you give the benefit of your insight into what the long-term dynamics of this market are going to be.

Harold Hamm

Yes, I’ll give a several talks on it recently, but I’d say that natural gas is unique it is everywhere. We see a lot of shale formations that are still being discovered and brought on for natural gas. We do not see that for along, it’s going to be a tougher deal for oil. It’s not going to be as rarely available just due to the generation process and all systems that are available.

So even though we’re working with a huge resource out here in the Bakken, you’re not going to see a ramp up so fast, as when change the price of oil supply in world, like natural gas is down in US. So I see that disparity staying for a good well. Gas price is actually held up a little better and ramp up, they would this summer or this spring rather. We’re selling May gas or June gas. So you tailed up a little better and slight to be inventory and gas storage, so I see that disparity hanging in for a while.

Operator

Ladies and gentlemen, your next question will come from the line of Chris Pikul with Morgan Keegan; please.

Chris Pikul - Morgan Keegan

Subhash and Gil actually asked most of my questions, but to clarify the previously announced Rognas well there in Richmond County, can you discuss the importance of that. Are the results there incrementally material to you guys and was that either of your Montana leasing activity directed around the Elm Coulee area?

Jeff Hume

Absolutely, Chris the Rognas well was the first time we’ve gone to the northern part of that play Elm Coulee proper. We’ve offset a 1280 then had a fairly poor well in it, open hole completed well and we performed 12 stage frac on this Rognas and have a 4,000 plus barrel type completion.

So we’re very excited about bring new technologies have been developed in the last three years and two and half years in North Dakota, the multistage fracs and you’ve seen what we’ve done as an industry in the last six or eight months with freezing the stage density and the sand concentration. So we’re very excited about our acreage in Montana, north of Elm Coulee and see in our presentation that golden triangle of area that we feel those just arrived for being tested by the industry at this time.

Operator

Gentlemen, your next question will come from the line Mitch Wurschmidt with KeyBanc; please proceed.

Mitch Wurschmidt - KeyBanc

Most of my questions have been answered. Just a couple quick one here, on your ECO-Pad, how should we at that going forward like how many rigs will be dedicated towards ECO-Pads, and how are you building these sort of ramping that up?

Jeff Hume

Right now, we have the two rigs on ECO-Pads, as we mentioned earlier the first one is Onyx. Second was, it got all four casing were set into the pay, one lateral is completed, we’re in the second well drilling the lateral. So within 45 days we’ll be probably doing the frac on that well.

We’re going to bring two more rigs in later month. We’ll probably drill single wells with those to just get the rig up in running and then we’ll move to an ECO-Pad. So in the future, we plan second half of 2010, we’ll have four rigs completing drilling ECO-Pad wells. Most of that’s going to be four well development for Pad and then we will have four fracs that will be executed in order right after that rigs moved off. So that’s what we’ll have if the rigs we want to commit with the Bakken for 2010. I would think in the future that would probably increase as we get more and more acreage into the development mode.

Mitch Wurschmidt - KeyBanc

Then are the increased number of fracs stages you’re discussing about over 30, are those on ECO-Pads as well?

Jeff Hume

Well, they’re very well maybe, with that maybe a good place to place those that the teams are looking at the different areas of Bakken that we have as you’re well aware the Nesson Anticlines 120, and 130 miles, north, south, rock characteristic change quite a bit over that vast area. So we’re looking at areas to test higher stages and to have comparison between the 24 and 30 and then maybe go to 34 and 36 stages in areas and see where that said.

We’ve looked at it from a reservoir engineering standpoint with mathematical stimulation models and it appears that the 24, 26 stages optimum, but that’s a model, so we have to go out and get a critical data and so, we’re going to do the occasional test of 30 or more stages to see where that ideal density fracs.

Mitch Wurschmidt - KeyBanc

I’m curious, how is your spud to TD, spud to sales time looking right now? Are you seeing any sort of delays on the completion side at all, just given the amount of activity going on up there?

Jeff Hume

I believe first quarter we’re probably around 28 days, we’re 26 in fourth quarter, we slipped a little bit, brought an quite a few new rigs trying in a lot of new folks that we just finished one well and we reached TD in less than 15.5 days. So when you get the teams trained and all the above add of it equipment and everything working, you can get very fast. So we’re optimistic, we can get our real-time spud rig release time back in that 24, 26 day range that we experience the second half of 2009.

Mitch Wurschmidt - KeyBanc

Anything on the spud to sales as well or completion time, I guess?

Jeff Hume

It’s running about the same, we’re inside of 75 days right now is bid for sale.

Operator

Gentlemen, your next question will come from the line of John Freeman - Raymond James.

John Freeman - Raymond James

I just want to follow-up on the Anadarko Woodford, as it was mentioned earlier, there’s definitely a lot of activity up in the northwestern part of the play up near Dewey. There’s been some other operators on various calls this quarter that have been talking up the Cleveland, the Tomco, etc., a lot of these other intervals.

I'm just trying to get a sense of kind of your thought process on when you plan on maybe testing these other zones, kind of what the game plan is and kind of when we should expect and see be kind of results from some of these other zones that maybe you haven't tested in the past in the play.

Harold Hamm

Well, that’s towards the northwestern part of our play in Dewey County, we have overrun overlap competition up there primarily for the Cleveland. We will be looking that as it develops within the area and certainly under our leaseholds. So that’s a the high potential and probability that we’ll see areas that develops as well as the historic play out there has been the [mal grip springer] that unrealized quite a bit areas as well. So we got several plays that kind of entertained right here along with this Woodford Shale probably that we’re pursing, that’s primary to us.

John Freeman - Raymond James

Then Harold, I believe there’s some legislation in Oklahoma regarding allowing greater than the 640 acre spacing. I believe the vote is this month, which would obviously be a good thing for you all and let you maybe develop at more closely like you did in the Bakken. Can you kind of talk to when that vote is and kind of your thoughts on it?

Harold Hamm

Well, we are trying to get it that for a vote and certainly there would be good for us. We can be a one vertical section and develop 1280s and 640 same as that $3 million of well about here that we’ve estimated $2 million to $3 million of well and that’s big, and sale of the operators here as Devon, everybody is working up there, same rigs and everybody else is poor; and that we just have to overcome the state statute to limits expiration to 648 acres in Oklahoma. So we’re trying to do that and OIPA is behind it and it looks good, we just have to good to the both.

John Freeman - Raymond James

Last question I had on Red River, which now that we’re kind of just is or close to the peak production level. What’s the base decline rate you are assuming on that, starting kind of next year?

John Hart

The base rig (Inaudible) on it, 10% to 12%, but we are looking at some other things we can do in the Red River units. We’re going to be moving some of our air compression equipment around that’s surplus now over in the Cedar Hills field, over in the Medicine Pole Hills and into the Buffalo area. We’ve got that in this year’s budget. We feel like with that additional capacity in those areas we can probably expand those fields, maybe even increase the productivity of those fields.

So I think we’re going to see in those Red River Units just continual investment yield pretty good returns. Right now, the rates return on the work we’re doing now is probably on way we have models over 40% rate of return, closer to 50% rate of return in today’s oil price.

So they’re very good low risk investments and infrastructure is pretty well built. We’re moving some of the infrastructure around, but moving the compression, I have that in place early next year we will be moving a second half of this year. So, we’ll be rolling in addition to that we have a private plan for CO2 in the Cedar Hills area. There’s portions of that we think could very well work, that is the CO2 being rejected off of the local gas plan due to the high pressure air process.

We have a glue gas of nitrogen, CO2 coming off that plan reject CO2s. We have a ratable CO2 for a pilot. We also have money budgeted for this year to execute that pilot and that’s how in the future two, three years, but hopefully we’ll get the pilot started this year, I have some data, a year, year and a half after now to roll and there’s quite a few folks planning CO2 for the area, didn’t various recent purchase of on course very strong indication. We have a line build up from the south and there’s a couple of coal gasification plants are being permitted at this time, that if they do come to realization, there will be quite a bit of CO2 available in the Williston Basin that’s probably five to eight years out of timeframe.

Operator

Gentlemen, your next question comes on the line of TJ Schultz with RBC Capital; please proceed.

TJ Schultz - RBC Capital

The wells in, you highlighted in North Dakota, I think I missed when you started using 24 stages. Is that the bulk of those on 18 stages or any on 24 stage fracs?

Jeff Hume

The 518 model we just updated to the bulk of the data that we used averaged around 20 stages. We had a mix of 24 and 18 stage fracs. I think its August of 2009, when we stepped up from 14 stage fracs to 18 stage, we’re doing some spot fracs at 24 stages during that period.

So the data set that we’ve used for the 518 model, averaged I believe arithmetically 20 stages per well and we’re doing the same thing now. We gone to a 24 stage base with some 30 possibly even higher stage fracs across the field and hopefully we’ll increasing our model 18 further out in the future, but as always we based on models on trailing performance not on future anticipated performance.

TJ Schultz - RBC Capital

The rigs, they are 23 now. I think adding a couple in the Bakken. Can you just talk about as we look to the balance of 2010, kind of your appetite for further rig additions moving through the summer?

John Hart

Well, with the body parts continuing to strengthen, we’re going to have to review that. We have an inventory that would support much higher rig count and plans our long-term to be ramping rigs up in North Dakota. We can easily handle 25 and just the North Dakota portion of the Bakken, as we open up the north of Elm Coulee field in Montana.

we can easily put a number of rigs over there, also there’s a tremendous amount of opportunity in those areas with rigs and the Woodford just takes the Anadarko portion, or current acreage holding, we could easily ramp that up to 10 to 15 rigs as we indemnified the economic areas of that and then let’s not forget the Arkoma Woodford that we’ve kind of step out of now due to this low gas commodity price, but it’s bulk of that HPP and it’s prime once gas price is start moving back up firmly above $5 million in Mcf will be able to put rigs in there.

So I think you’ll see as continuing to grow our rig count we’re going to have our struggle will be staying within cash flows as close as we can, stay inline with that as we grow and with increased performance and the increasing commodity price we’ll hope to be able to ramp that activity earlier than later.

Operator

Gentlemen, your next comes from the line of Bob Carlson with Janney Montgomery Scott; please proceed.

Bob Carlson - Janney Montgomery Scott

Just could you expand a little on your hedging program?

Harold Hamm

Yes, we can. We’ve been underpinning our drilling activity over the last several months by layering in hedges that specific times, we’ve been on opportunities back in the winter there, we hedged a quantity of natural gas, but it is also glad we did; and that was a pretty good prices I think 638 was up a highest and so in our 2010 volumes and add into 2011 hedge. So there comes opportunities that you can do that and we’ve got a habit of doing that on the count layer, I mean as opportunity arises and John, you want to cover in a specifics.

John Hart

Sure, we’ve got positions in place for crude and natural gas for the next two years, the remainder of ‘10 and into 2011. In ‘10 we’ve got about 19,000 barrels of oil hedged and about 40,000 Mmbtu of natural gas hedged for the full-year. Going into ’11, as you can imagine, we’ve got a lower amount of sales that we tend to systematically stepping the positions.

So we’re looking more towards the near terms, a smaller amount into the future, but as we continue to go through the year, we’ve made very little layer in some additional positions in ’11 and then again walking into ’12 at that time. We believe that’s a good for measured to underpin our economics and our drilling plans in relation to large growing sustainable asset base that we got out there for our future developments. So Landman, again we got smaller positions, we got about 14,000 barrels of oil hedged and about a 32,000 of Mmbtu of natural gas hedged in those periods.

Operator

Gentlemen, your next question will come from the line of Steve Berman with Pritchard Capital Market; please proceed.

Gail Nicholson - Pritchard Capital Market

This is actually Gail Nicholson, setting in for Steve. I was wondering, regarding the Steadman well, what number of frac stages did you use and what was your lateral length?

Jack Stark

The statement was a 24 stage frac and the lateral length was approximately 9200 foot.

Gail Nicholson - Pritchard Capital

Then with you moving, some another rig into that the Nesson Anticline area, how many wells do you expected to drill on remainder of the year there?

Harold Hamm

I don’t have a good account or estimate of that. We’re going to have five rigs working with west of the anticline second half of the year. So that’s going to be 30 gross operated wells out there probably 65%, 70% ownership out there, so 26, 28 net wells.

Gail Nicholson - Pritchard Capital

Then my last question regarding the Cana, you have 205,000 acres, what would you consider core? I know you're still developing and everything, but as of now based on results of that acreage amount, what would you considered to be your core?

Jack Stark

Well, 65% of that of our acreages is Northwest of Cana, where we’ve already got it data point with far Northwest end of it. So if all that fills in, I’d say we’d have over 130,000 acres in the core area of Dunn and Blaine County, trying in the West Cana field after the west. To the south, we have around 75,000 acres that scenario where were seeing very high liquid content very rich gas that the area two the Northwest up and doing Blaine as around 1100 Btu gas and we’re saying from zero condensate 30 and 40 barrels per million in that area to the south.

As I mention in the presentation, the latest well of the dollar has a yield of 200 barrels per million and a gas of about 1500 Btu. So you’re getting even though it might be less production rate, you’re getting much higher realize price at the well here getting close to $9 per Mcf, well at Mcf last month.

Gail Nicholson - Pritchard Capital

With the three rig program, you have operating there right now? How many rigs do you plan on drilling for the end of the year?

Harold Hamm

At this time, we have three rigs planned for the remainder of year. We just moved in the third rig and will be, as I said during a checkerboard across that entire acreage package to delineate economics based on liquid recovery in productive of the wells.

Operator

Gentlemen your next question will come from the line of Brian Kuzma with Weiss Multi Strategy; please proceed.

Brian Kuzma - Weiss Multi-Strategy

First question, the acreage that you guys added here 128,000, how much roughly that was in Q1 versus post Q1?

Harold Hamm

A bit we had with 100,000 Q1 and 28,000 thus far in the second quarter. We did quarter bit a work in the first quarter there, Brain.

Brian Kuzma - Weiss Multi-Strategy

Then you guys gave the 24-hour test rate on the wells you guys drilled it like 1,400 barrels a day. If I wanted to compare that to the older dataset, you guys, if you have seven day rates. What would be a reasonable number for the seven day rates?

John Hart

I think it would be around about 900 barrels equivalent a day.

Brian Kuzma - Weiss Multi-Strategy

Then I wanted to ask of your North Dakota acreage, if you guys have stepped out and drilled these other Three Forks wells, how much of it just on a percentage basis do you think it will work on the Three Forks?

Harold Hamm

Brain, I think we’re still inline with, earlier thought that’s about 75% of our acreage that we had estimate out there. So, that’s a gas until we get it more define, Stark comment on.

Jack Stark

No, we’re just encourage it what we see out there. We’ve see course that they have good saturation in Three Forks and continues to fit our geological model that the Three Forks is one of two reservoirs in this Bakken system here and so, we continued to be encouraged more sort of been discouraged it all about the Three Forks that we go through play.

Jeff Hume

Brain I think what we’re seeing as an industry across the entire Bakken is that the Three Forks has where we has porosity it saturated and we’re even seeing that south of the feather hedge you have winding drills some wells down there that they’re completely pass the edge of the Bakken and they’re seeing oil in the Three Forks and the key is going to be where do I have Three Forks only where do I have Middle Bakken only, where do I have them both where they produce to gather some areas I think, you have enough fracs where there producing get as far as you get some of these very high yielding wells and other is going to have do well reservoir development.

So as Harold said, we feel like right now we’re probably 75% of our acreage will have do well reservoirs development in that area. So this latest test add on Western Williams Country, where we drill with only 38 feet or space between the top of the Middle Bakken and top Three Forks is going to key as we gets production on that, come back in and drill at Middle Bakken well that we frac up into Middle Bakken with the Three Forks in the Obert well or not and that won’t take a year two to learn and unfortunately it just takes the time. The good news is, both horizons produced and that just increase as your total oil and plays that’s there to be harvested.

Jack Stark

I just have here too, oftentimes people question of Three Forks and the Middle Bakken production and where does the Three Forks produce, actually the Three Forks underlies the Bakken system completely through here, in fact it’s productive limit will probably expand past actual Middle Bakken because it pinches out before you ever, it pinched up and before had the hedge of the Three Forks potential window there.

So as Jeff said, the big deal here is where do they act independently and where do they not and that’s going to just be a matter of time and then testing and right now we demonstrated over a large portion of our area right now of our acreage position up along in Nesson Anticline that we see separation between the two which is very encouraging and increases of potentially replace as [NDIC] as indicated here in their recent report.

Brian Kuzma - Weiss Multi-Strategy

So that 75%, is that just really a dual development? Is that just on the Nesson or are you now including, I think too early to conclude that out with?

Harold Hamm

No I think too early to be conclusive as to the amount and where these two are separate on the extreme west side, but with work that winding has done down to the south of Anticline and obviously the Three Forks does extended of the Anticline, the good ways and we’re very much encouraged by and up and front the Bakken itself.

Brian Kuzma - Weiss Multi-Strategy

Then I just wanted to clarify, question someone else asked earlier. Just in terms of, due to ramp up activity. I've got my model here and if production ramps up pretty significantly in North Dakota, and I'm curious if there's any sort of hiccups you guys see along the way or delays that would make it so my simple model wouldn't work out?

John Hart

We’ve done everything in our parity trying eliminate those hick-ups from plan ahead on equipment with a contract in rigs let just say, what we done on the acreage, oil prices are always unstable, if you know of all times so will, what we can underpin that with hedges and protect yourself up there, but it does ramp up quickly as you probably less that hasn’t talk about their investment, and how that would ramp up and we run our model out same way and sure now shows the same type of results, it was indicated five hedge so I don’t know, we work trying to eliminate anything that might cause a hick-up and plan ahead and I think we’ve done it pretty well.

Operator

Gentlemen, at this time I show no further questions with in the queue. I’d now like to turn the call back over to management for any closing comments.

Harold Hamm

Well, thanks all of you for joining us today. We had magnificent start on, what should be the tremendous 2010 both in terms of operating results and financial results appreciate all our question as very good ones. Remember on first base, Continental has all rich inventories has been service very well. Second base, superior economic approval, I don’t see those gone away very quickly.

Third based, tremendous lease position, great valuable lease position up here in the Bakken; and of course and then, improving new well in the Bakken AUR at 518,000 Boe and that’s based on 20 state fracs, we’re doing more of those today. We’re posting that number, should see that number improve in future, and of course the NDIC study the came out and confirmed while we were doing in the Three Forks.

In our home run, we’ve had a home run in the past we’ll see one in the future from a ramp up further production growth with comment on future. For the balance of the year, number one, 2010s guidance of at least 13% production growth still in place; number two we’re capitalized on the strong position in all cost price and gas, liquids price; number focus on operating discipline to create maximum value per shareholders. Thank you for you participation and your call.

Operator

Ladies and gentlemen, we thank you for participation in today’s conference. This does conclude the presentation. You may now disconnect. Have a wonderful day

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Source: Continental Resources, Inc. Q1 2010 Earnings Call Transcript
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