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Continental Resources, Inc. (NYSE:CLR)

Q2 2010 Earnings Conference Call

August 5, 2010 10:00 AM ET

Executives

Harold Hamm – Chairman and CEO

Jeff Hume – President and COO

Jack Stark – SVP, Exploration

John Hart – CFO

Rick Muncrief – SVP, Operations

Analysts

David Heikkinen – Tudor, Pickering, Holt & Co

John Freeman – Raymond James

Stephen Berman – Pritchard Capital

Joseph Allman – JPMorgan

Scott Wilmouse – Siemans Incorporated

Amir Arif – Stifel Nicolaus

Noel Parks – Ladenburg Thalmann

Brian Corales – Howard Weil

Irene Haas – Canaccord Adams

Jennifer Jurrius (ph)

John Daily (ph)

Gil Yang – BofA Merrill Lynch

Subash Chandra – Jefferies & Co

JT Schultz (ph)

Operator

Good day, ladies and gentlemen, and welcome to the Continental Resources Second 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 with an overview of the company’s second quarter achievements 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, additional members of management will be available to answer questions.

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

Harold Hamm

Good morning, everyone, and thanks for joining us this morning on our conference call. Today, we’re pleased to review our excellent second quarter results, even our long-term investors may not realized that along with the passion for finding along gas, Jeff Hume and I have a passion for vintage sports cars, Chevrolet Corvette to be exact.

Jeff has the ‘65 Corvette that he’s owned since 1970, some 40 years. I, on the other hand drive a fully restored Black ‘60 model, which I bought a few years back. Driving an old Corvette in top shape gives you an appreciation for precision and power.

My point, that’s how Continental Resources is driving right now. We’re cranking up the RPMs and have nothing but open road in front of us. As you saw yesterday afternoon under press release, we increased production to almost 42,000 Boe per day in the second quarter of 2010. That is 9% over the first quarter of this year, and 12% higher than the second quarter of last year.

We’re on track to meet our guidance for the year, 15 to 17% production growth, with much stronger growth in 2011 as we continue to add rigs between now and year end. Currently, we are producing almost 44,000 Boe per day and we expect to exit the year at about 50,000 Boe per day.

Clearly, crude oil is fuel in the tank. It was 75% of second quarter production.

Our production in North Dakota Bakken continued to increase in high gear. In the second quarter, it was almost doubled what it was in the same quarter last year.

Also our production and Anadarko Woodford became significant this past quarter. We generated 1,079 Boe per day in the Anadarko, a combination of rich gas and condensate. This will continue to increase as we rapidly put more rigs to work and apply and continue to drill with the rigs that we have already.

On October 12, we’re going to have an Investor Day in Oklahoma City, at that time we’ll layout the detailed roadmap for growth over the next several years.

We’ll dig deeper into Anadarko Woodford or Bakken and then Niobrara, which will be the key engine for our growth. The presentation will be audio webcast and we’ll post slides after on our websites.

Production in our Red River units also remains solid as we drill new wells this past quarter.

There were two key factors to it growing along gas sales by 49% this past quarter. First, we increase production. Second, we benefited from the strengthening crude oil prices in the last year. We saw strong growth in EBITDAX in the second quarter. It came in at 212 million that was almost doubled EBITDAX for the same period last year and 18% stronger than the first quarter of 2010.

We expect further growth in EBITDAX. We continue to layer in hedges when we see a good opportunity as we did earlier this week, and even today. We want to make sure we have a horsepower to sustain the momentum of our drilling program for the future with (inaudible).

Finally, at the bottom line, we reported $0.60 per income per diluted share. This compared with the $0.08 per share last year in the second quarter and $0.43 in the first quarter of this year.

So, just like a Corvette, Continental was burned on all cylinders. The people at Continental are doing a great job for the shareholders. Last year – yesterday, where North Dakota and went to the Glaxo Ramo ECO-Pad and we saw a rig there that moves from one hole to the other within only an hour. You don’t even have to move the backyard in this drilling operation. So, we think that our estimate 10% cost savings for doing that is going to be right on target. Our (inaudible) performance at a high level as we add rigs, strengthening our acreage position, liquids risk, high-value shale place and prepare for even stronger growth ahead.

On July 9th, we grab another gear and announced a 53% increase in our capital expenditures budget for 2010. This allowed us to take advantage of the opportunity to add acreage on our oil risk (ph) price. During the past six months, we were able to acquire significant acreage for $250-400 an acre, and we say base on recent sales this acreage now worth 10 times as much or more. De-risking, of course, and further development will increase that value even further.

There is not an acre that we bought that I would care to get back. Based on our knowledge to the Bakken play, we correctly predicted the bun in both drilling activity and land base. Associated with those two components were secured drilling rigs and frac equipment ahead of this trend.

Activity has now doubled to more than 140 rigs to North Dakota and land value have increased significantly as demonstrated by recent M&A transactions up there.

A recent leasing activity is completely consistent with Continental’s long-term growth strategy. It has two key components. First, we focus on conservative fiscal management. Second, our expiration strategy emphasized boldness when we spot a compelling opportunity for organic growth as we recently have seen.

This expiration strategy is fourfold. First, we build a geologic concept of the play. Next, we get in and lease before costs escalate, of course, many times it’s been in a basin or region that’s our favorite at that time, as it was up there in the Wilson basin. Third, we build a large acreage position and we can leverage with our operating expertise. Fourth and final, we maximize our economic submitted play, such as ECO-Pad development.

You’ve seen us accomplish these several times. We applied this strategy in Oklahoman some 30 years ago, followed by the Red River units at Cedar Hills, Elm Coulee in Montana, of course, the first horizontal play, and the North Dakota Bakken.

More recently, we built strategic positions in Anadarko Woodford extension in the vast Niobrara. So, we’ve been consistent in our approach. Continental’s list inventory provides long-term support for accelerating growth to many years.

And of course, you have to pamper a vintage Corvette, when not on the road. She should be parked in the garage, under cover. We’re the same way about our company. We’re known for being good stewards of capital and a good steward use a debt to take advantage when it has an opportunity to create significant shareholder value. This is why we’ve kept that low over the years to give us flexibility at a time like today, so we can capture high-value opportunities and that’s just what we’ve done.

We’ve sold and continued to market non-strategic, but valuable assets. This will offset some of the hard cap expending. We sold acreage in the Haynesville in the second quarter and booked a nice gain, and we have other high-value assets we’re marketing today.

So, now, let me talk to you about these three excellent opportunities for growth. The Bakken, Anadarko Woodford and Niobrara.

First, let’s look at the Bakken opportunity. Continental has built a commanding land position in the Bakken, taking advantage of the competitive strengths that we’ve accumulated in play over the past decade. During the past 10 years, we’ve assembled the best historical database of leasehold in North Dakota in Montana. This allowed us to move very quickly to seize the opportunity as the play expanded. We’ve assembled the largest land position in the Bakken and we’re expanding that position, and we operate the most rigs in the play today.

This January 1st, we’ve grown our land position by 171,505 net acres that equates to total of 270 net wells on 640 acres space and for one zone. That’s a total of more than 100 basin barrels in reserved potential and if you count the Three Forks, it’s even larger. It could be double. We’re talking about prime acreage along Anadarko and West Woodford in McKenzie and Williams County as the play has expanded in that direction.

In Montana, we added to your possession Roosevelt and (inaudible) counties. These varies have been significantly de-risk by recent drilling activity and will deliver high rate return for us.

Second, let’s talk about the growth opportunity in Anadarko Woodford. Most operators at Anadarko Woodford last year on what they call the poorer the play, mainly in Canadian County, Oklahoma.

Our geologic models on the other hand indicate that the productive Woodford extended significantly to the Northwest and the Southeast. Our Anadarko team delivered a model that told us this play was a prime resource opportunity. It’s a lot bigger than everyone thought. It’s a hard type of resource play being liquids rich and it’s very prolific. Developments in the Anadarko Woodford since January this year validated our geologic model.

And let me just give you the latest example. In a release yesterday, we announced the Doris 1-25H, a strong confirmation well that four miles out to the Brown 1-2H. The door explode at a test rate of 4.5 million cube feet and 72 barrels of condensate per day confirming that the Brown was repeatable success in Dewey County and extending the play for more than 45 miles Northwest by the Canadian County activity.

Clearly, the rest of the industry is paying attention to our wells. A recent acreage sale by another operator in Northwest Canada demonstrated how invaluable Continental’s Anadarko Woodford lease position has become. Drilling results continue to demonstrate the strong productivity and a significant liquids component or a characteristic throughout much of the play here.

There are currently 21 active rigs, active in Anadarko Woodford and that number is growing. We’ve increased our position to Anadarko Woodford with 251,626 net acreage in total. The Anadarko Woodford overlies the deeper portion of the Watonga-Chickasha (inaudible). Many of these Woodford penetrations that will drill in the future will encounter a token, spring or brick productive intervals, just like our new Redwood well recently did. These will require additional wells to be drilled or harvest these zones of serendipity. This is additional upside to the play.

Finally, before I toss you over to Jeff. Let’s talk about the third growth Niobrara shale pad. You’ve all read about the quiet revolution in natural gas and the way that horizontal drilling n and multistage frac technology had made the United States the number one natural gas producer in the world.

New technology has also been somewhat of the game changer in U.S. oil expiration creating valuable opportunities that harvest all fat traded, but tight reservoirs that had been previously uneconomic. This is exactly what has happened in Niobrara.

We’re not a newcomer out here in this play. In the early 1990’s, Continental was drilling horizontal wells in the (inaudible) Field prior to the advent of multi-state fracing, which has now opened the door for widespread development. We do know this play very well. We’ve leased some 60,000 net acres in Colorado, Wyoming and are still actively leasing. We plan to spot our first well in the last quarter of the year and Jeff will have more to say on our outlook here.

So, with organic growth opportunities like the Bakken and the Anadarko Woodford, what do we see down the road for Continental? As we said in our press release, we geared up for a multi-year period of exceptional increases and production improved reserves and earnings, we’re adding rigs and we’re adding experienced professional server teams to help us manage our growth.

As investors, you should expect strong production and earnings growth in the second half of the year. Next year in 2011, you will see even higher production and earnings growth. The engine is driving our momentum and helping us generate increased production earnings as our oil rich drilling inventory. This inventory will propel us forward for the next five years, 2015.

Our new vision is to triple the size of Continental over the next five years to organic growth. Historically, we’ve doubled every five years. Now, we’ve set a chorus to be three times our current size by year end 2015. That is the road ahead. We’ve mapped it, fueled up for the trip and that’s where we’re going.

As a company CEO and largest shareholders, I’m convinced we’re on track to create significant value. Some of you have asked from time to time while I’m still doing this, coming in here at the office every day, assessing expiration opportunities and working with the teams in the field. Well, this is as well as I can I’m proud of what we’ve accomplished together at Continental, but even more I’m excited about what Continental is going to be. I have a passion for building great companies and its fun. It’s like revving an old Corvette up and shifting her through the years.

Jeff?

Jeff Hume

Thanks, Harold. I’d like to expand on the three growth opportunities that we have in the Bakken, Woodford and Niobrara, and give you some more operating detail from the second quarter.

So, first, let’s talk Bakken. Once again we had record production. A 93% increased in North Dakota for the quarter year-over-year, and Montana is holding its own with only one rig running.

In the second quarter, we’ve participated in completing 50 gross wells in the Bakken and all but one of those was in the North Dakota. Focusing just on Continental operated wells, we completed 22 gross or 10.4 net in North Dakota. Our standard completion design is currently 24 frac stages, but we completed one 30 states frac last quarter, the Roger 1-18H in Dunn County. It is a solid producer, testing at 1,486 barrels oil equivalent per day.

Our Three Forks well tested an average 1,191 barrels of oil per day and our Middle Bakken wells averaged 1,069. We noted several Three Forks and Middle Bakken wells in our press release last night. The key takeaway is that the average well results continue to improve. This is especially true when you look at our average 30, 60 and 90-day projection rates, which are the meaningful indicators of early well performance. Production growth trend is on solid grounds.

Today, we have 18 operator rigs in North Dakota Bakken, one in Montana and moving a 19th rig in the North Dakota. We will have an additional rig in Montana by year end. Three quarters of our North Dakota rigs are drilling undeveloped acreage; surround pace to establish production to meet our list commitments through the remainder of this year and through 2011.

Many of you remember us predicting two years ago that we would eventually need 20 rigs in the Bakken. We’re almost there today and with the growth and our position in the play, we could easily accommodate 30 rigs.

Let’s shift our attention to Montana, going forward, we plan to alternate between infield drilling and pulley (ph) and drilling step out wells north and east of the established fairway.

Our drilling activity in North Dakota on the other hand is clearly spending all across the play, moving west from the Nesson Anticline as this play expands back into Montana.

Currently, we have seven rigs drilling west of the Nesson Anticline yielding solid results. One of these rigs is drilling immediately north of Lewis and Clark area, a new area for us. The remaining 13 rigs in North Dakota are working up and down the Nesson Anticline. Three of these are walking rigs that are drilling ECO-Pad locations. We look forward to reporting our first ECO-Pad results in the next few months.

Harold and I were in the field yesterday, and ECO-Pad projects are going very well. We just fraced our first four well pad and are preparing to frac the second. We plan to have a total of five rigs drilling ECO-Pad projects by year end.

I would like to point out that the drilling activity by Continental and other operators is rapidly de-risking the areas west of the Nesson Anticline. A total of 40 wells had been completed west of the Nesson Anticline in the last 18 months with average tips production of approximately 1,800 barrels oil equivalent per day. By our latest count, 30 rigs are operating in the area, further delineating the play.

Our development drilling has demonstrated that 640-acre spacing is warranted and we anticipate that 320-acre spacing will also be needed to effectively drain the Middle Bakken in Three Forks reservoirs. We’re already developing on 1,520 foot inter-well spacing or 320-acre equivalent in the Elm Coulee Field of Montana.

We believe the same could be done both the Three Forks and Middle Bakken zones in North Dakota.

To date, we’ve drilled nine pairs of Middle Bakken Three Fork wells using 660-foot staggered offset development pattern in various locations along the Anticline. The results thus far have been excellent.

With so many operators adding rigs in North Dakota, the growth in state production has been dramatic. According to a recent report, July production totaled 310,000 barrels per day, that’s a 19% increase just since February. IHF’s research predicts that North Dakota production will triple this volume within this decade. So, it’s no surprise to see the availability of both service and capacity is tightening.

But as an early and leading operator in the play, Continental has already with drilling, service and pipeline companies. We have dedicated completion service crews under contract and continue to work with drilling contractors could bring new rigs and cruise in to North Dakota and Montana.

In terms of takeaway capacity, Continental holds an advantage as an historical shipper. We’re positioning ourselves for additional pipeline capacity as being develop. One example is the Keystone XL pipeline. We work with TransCanada and the State of Montana to provide for an on-ramp for Bakken crude oil delivery to either Cushing or Houston.

We’re also contracting for railroad shipping to bridge capacity, while pipeline projects are being completed.

In a revised 2010 capital expenditure budget, the Bakken is allocated 890 million CapEx, of which 643 million is for drilling operations and 247 million for land. We plan to drill 232 gross or 85 net wells in North Dakota and 14 gross or eight net wells in Montana for the year.

Now, let’s shift to the Woodford shale play in Oklahoma, our second growth opportunity.

We’re very pleased with the results of the Doris 1-25 in Dewey County. As Harold mentioned, it’s located four miles south for Brown 1-2. The Doris confirms that we are in a liquids rich area with strong oil productivity. The performance of the Doris is very similar to the Brown. The Brown has produced 920 million cubic feet and 13.4 thousand barrels of condensate since completion in September of 2009. It’s currently producing 2.4 million cubic feet per day and 28 barrels of condensate. With projected EOR above seven Bcf equivalent.

Forty miles to the southeast, the Young 2-22 also continues to perform well. It has produced 1.2 Bcf since its completion in August of 2009. It is currently producing 2.9 million cubic feet per day and will have an EUR of above seven Bcf. The Young located in Southern Blaine County is an in a dry gas window to play and does not produce condensate.

Given our continued successes, combined with drilling activity by other operators, we’re confirming a widespread productive potential as the play. The Anadarko Woodford is now recognize as extending from Custer County, 30 miles north and then 50 miles east across Dewey and Blaine Counties. In fact, a 30 by 50 mile block Northwest of Canadian County, the original focus of the play. That is over 1 million acres field expansion that is ready for development.

We have three rigs working in Anadarko Woodford and we’ll add four more by year end. We’re drilling exploratory wells across the Northwest Cana extension and in Southeastern part of the play.

The Dana 1-29 is now drilling Brady County. As you recall, our first two tests in the Southwest Cana had high liquids production. The Ballard is field yielding over 200 barrels of condensate per million cubic feet of gas. The Dana and the subsequent well will test a new concept in area by landing the lateral wellbore in what should be a more brittle section of the formation. We look forward to the results on the Dana in late September.

Although much of our focus in the Woodford has shifted lately to the Anadarko, we’re continuing to see positive results in our Arkoma Woodford in Eastern Oklahoma.

In the second quarter of 2010, we completed the Marilyn 1-29H, 79% working interest and the Delphia 1-34H with 97% working interest in Pittsburg County. These wells are the first two that we’ve drilled using the results of a 5-square mile 3D seismic shoot that was finished earlier this year in our East Krebs prospect. The Marilyn flowed at 4.2 million cubic feet per day, while the Delphia flowed 2.1 million cubic feet per day in their initial one day test.

The other notable news for the quarter is in the Arkoma involvement non-operated well in the Southern part of Ashland Prospect, where we own significant acreage and worth for production. This was the first horizontal well targeting the chrome oil sand. The Ina (ph) 7H-12, which we own 8% working interest flowed 8.4 million cubic feet per day in its first one day test, so it appears we may have another prolific zone to target in our Arkoma acreage.

We have allocated 230 million in CapEx with Woodford as a whole. This includes 160 million for drilling operations and 114 million for land and seismic. We plan to drill 17 boroughs, nine net wells and in the Anadarko Woodford and 52 gross, nine net wells in Arkoma this year.

Harold identified the Niobrara as our third growth opportunity. The Niobrara is a huge crude oil resource play. It covers over 3 million acres and has a potential to produce more than 2 billion barrels of oil. We’ve established a strategic position in the play, leasing almost 60,000 net acres and continue to acquire result. We hold acreage in Platt, Laramie, and Goshen Counties in Wyoming and a well count in Colorado.

Our leases are in proximity to several of the most interesting test wells drill to date. EOG kicked off recent search and drilling with five horizontal wells including the Jake 2-1H, which IPed at 1,558 oil equivalent per day and it average 555 barrels oil per day over its first 90 days.

Noble has announced four wells that produced an average 585 barrels per day over their first 60 days production, including one that average 1,000 barrels oil per day.

Niobrara development is currently on 640 spacing and we believe the play can accommodate 1280s. We plan to spot our first Niobrara well in the fourth quarter. Continental’s entry into the Niobrara is a natural strategic fit with our expertise and experience in horizontal oil resource plays.

That concludes my quick look under the hood. So, now, I’ll turn it over to the operator for Q&A and thank you.

Question-and-Answer Session

Operator

(Operator Instructions) Please standby for your first question. Your first question comes from the line of David Heikkinen. Please proceed.

David Heikkinen – Tudor, Pickering, Holt & Co

Good morning, Jeff, there is Brian Lively here as well. We’re just kind of going through and your comments about the Niobrara accommodating 1280 acres spacing, can give us some thoughts about the geology and the differences across Wyoming and Weld county and also as you think about the other operators well results, are there any different really play concepts that you’re seeing that they’re testing?

Jack Stark

Hey this is Jack Stark. I’ll take this one to first starters. The Niobrara itself is as these all these resort plays that we’re evolved with has really very, very wide spread board development. As Jeff said this thing is covering three million acres our here and we see this whole area is having potentially be one large continuous oil reservoir. So really drilling these wells on 1,280 acre spacing really makes sense because you get most economy from the drilling the vertical well and those – the incremental dollars that drill from the 640 on through a 1,280 those are really effective dollars well spent and there is really no evidence or no reason not to continue to drill that if we can get the regulatory bodies to allow us to do that.

The only challenge we would have is in the Niobrara and in any of these plays, you do see faulting occurring and that faulting can cause you some problems with the geo steering but with 3D seismic, we can anticipate those and basically design our well board pass and to either avoid or recognize they are coming and drill across them, we’ve done that in the Woodford and so really it really just comes down to more of a regulatory issue not a geologic issue as to whether or not we can drill 1,280.

David Heikkinen – Tudor, Pickering, Holt & Co

And how much of your acreage do you have covered with 3D?

Jack Stark

In Niobrara small portion at this point, we’re making plans to do that, we do have our first initial location, we do have 3D seismic there. We’re in the process of filing the permit. We’ve got the well staked and expect to be able to drill ahead here sometime fourth quarter.

David Heikkinen – Tudor, Pickering, Holt & Co

That’s interesting. And then just, taking a step back and just thinking about each regions, and with the Eco-Pads you mentioned you’re saving about 10%. Can you walk us through what does that mean for targeted well costs given costs are going up, you kind of hold the line in the Bakken and then kind of talk as well around at well costs and how you’re managing costs in the Anadarko Woodford?

Jack Stark

Certainly the well cost in the Bakken currently is, we’re running around $6 million with a 24 stage frac on a single well location. So we can – we feel like we’ll save 10% on that on our Eco-Pad locations. We are seeing pressure as production ramps up, activity ramps up on those cost and I think we’ll continue to see that, where it will go is anybody’s guess, but we’re doing all we can to hold the line by entering into a long-term arrangement with our vendors and we’re doing that and working well with them, have great relationships with them.

In the Woodford, we are bringing new rigs and at the present time, we’re keeping those cost stand. We’re working with several frac simulation crews at this time to work out long-term arrangements to have supplies of equipment and horse power to handle our expected ramp up and activity in that area.

Currently we’re seeing our cost in that play of around $7.2 million. We feel like we can work that down as we’re very early in the play at this time. We’re meeting with, we’ve met, we’ve bid companies, we’re looking at designs of bids where we can drill these wells faster and much like if you’ll recall two years ago it was taking us 45 days to drill a well in North Dakota.

We’ve drilled several wells at 16 days from spud to rig release or spud to TD in the North Dakota, Bakken. Right now our average up there even with the ramp up is around 28 days. We slipped a little bit and that’s just new crews getting them trained up. But as we continued to improve in both the Woodford and the Bakken, you’ll see those cost come down just due to efficiency.

Now yesterday when we were up on our Eco-Pad rig when we were visiting there, they drilled over a 100 feet of hole, while we were out there visiting and it’s just amazing how fast, it’s just hard to imagine your 10,000 feet deep, they were 4,500 feet out and looked like you’re drilling surface hole. It’s just amazing. I never would have believed it 20 years ago.

David Heikkinen – Tudor, Pickering, Holt & Co

And then on the financial side using debt to build and outspend your cash flows as you’re building some acreage. Can you talk about kind of thresholds, what metrics you use for debt, I mean is there a debt-to-cap threshold, is there debt-to-proved reserves or debt-to-EBITDA that you think about that you’re comfortable with as you continue to do some leasing this year and next, and fill more as well.

John Hart

Certainly, this is John Hart. We try over a longer period of time to keep it very strong stable balance sheet that enables us, when we do have opportunities to take advantage to those opportunities. We look at debt-to-cash flow is certainly one and we’d like to stay around one to 1.5 times cash flow liner but we also focus strongly on book capital when we tend to keep our debt in the all around 40% of book capital that type of range and keep it in a relatively conservative with strong position and take advantage of opportunities when we have them, but didn’t try and reduce it in periods where we go up, then subsequently reduce it as the production comes on.

David Heikkinen – Tudor, Pickering, Holt & Co

That’s very helpful. Thanks guys.

Operator

your next question comes from the line of John Freeman. Please proceed.

John Freeman – Raymond James

Good morning guys.

Harold Hamm

Hey John.

John Freeman – Raymond James

Yes the first question on the Anadarko Woodford, y’all had guidance on the EUR’s there for a while of about 5.4 B’s, and I’m just curious that now that we’ve got some data on some of these wells that have been on line for a year or more, you decided one of the early wells it looks like it will be over seven B’s if you have sort of a revised guidance are you just sort of sticking with the 5.4 number?

Harold Hamm

Well I think we’ll be seeing that come up John and as always we’re going to be conservative on locking that up. We’ve got three wells down in the Northwest part of the field, the brown, the young and of course the Doris is very young, all three of those are on track to produce over 7 Bcf maybe higher maybe higher than that. We’ve got a three more wells just frac one and have been we’re tracking another one today. I think when we get a little bit larger database you’ll see us raising that. So I think next quarter we’ll be announcing a revised number and I think from what we’ve shown you already today, the first three or seven so it’s going to be a significant increase, I think it’s going to be 7 Bcf or above, that’s where we’re going to be going to but until we get dataset, I hate to over commit.

John Freeman – Raymond James

Okay, and then maybe I missed this answer in response to David’s prior question. What’s the current ASC on the Anadarko Woodford wells?

Harold Hamm

It’s running about $7.2 million what we have in our economic model.

John Freeman – Raymond James

Okay and then on during the quarter you had the asset sale in the Haynesville obviously you’ve got a decent amount of acreage in like west Texas, Illinois basin. Is it safe to say that there is still kind of ongoing asset sales that you’re looking at?

Harold Hamm

Yes, there is, we’ve got some acreage in the Appalachian area, the three different packages out there right now, there were marketing, we’re doing that ourselves, have a lot of interest in that. I think we’ll be selling those and we have another acreage package that we’re marketing at this time also. So I think we’re going to be and doing well there. We also have in North Louisiana and besides the Haynesville which we did sell, we have some acreage in Bossier trend that we’re marketing at this time.

So our overall plan is to clean up some of the acreage we have in different place that we’ve try to establish a foothold in. It’s very good acreage, very strong acreage but we’ve decided to focus on our core and that’s oil resource plays and so we’re selling that, we’re selling at a good value and we think that will offset quite a bit of our capital expenditure increase we have this year.

John Freeman – Raymond James

Okay, good and then last question I have, and I will turn it over to somebody else. In your release y’all provided your estimate on the gas price differential. Can you give an update on what you’re expecting for the differential in the Bakken in the second half of the year?

Harold Hamm

Yes, I am going to have to look that to get drilled down to the Bakken, I don’t have that at my finger tips. We saw overall the 25% premium to NYMEX for the quarter. The Bakken was a small percent of that, I think we get a little larger premium than that in the Bakken because it is fairly rich gas.

John Freeman – Raymond James

Well, I’m sorry, I wasn’t asking for that, the actual oil just on the Bakken crude that you’re selling, yes sir?

Harold Hamm

Crude oil. My brain heard gas. Crude oil we’re seeing that our guidance is 8 to 10. We saw it kind of blow out in May and that was mainly just a marketing the refinery turnarounds, that has come back in. we’re in the on the market side around $3 then we have a transportation component that’s $2 to $4. So I think we’re going bask back a good portion of oil being the $7 or $8 range. But I think that this goes right back to the point we’ve made previously is that the differential move from month-to-month and that the biggest compound of it is the market is what the refiners are willing to pay.

So that’s what we’re seeing. So overall I think we’re going to be within our $8 to $10 guidance that we’re providing.

John Freeman – Raymond James

Great, thanks a lot guys.

Operator

Your next question comes from the line of Stephen Berman. Please proceed.

Stephen Berman – Pritchard Capital

Good morning guys.

Harold Hamm

Good morning Steve.

Stephen Berman – Pritchard Capital

Jeff the wells you listed in the Bakken, in the press release, are any of those west of the Nesson, either on the three forks or the Bakken?

Jack Stark

Yes well the answer to that will be one of those bids, this is Jack and its listed the 1,088 barrels oil equivalent per day.

Stephen Berman – Pritchard Capital

Okay, and maybe some other completions that aren’t listed in here that you’re seeing similar kind of rates or…

Jack Stark

Yes, we’ve actually got six wells completed out there right now and the average IP on those is about 1,100 barrels a day. So we’re seeing nice completions out there consistent with the type of result we’re seeing from the other operators out there. This is right on the Montana, North Dakota border. So its way out there and so we’re very encouraged with what we’re seeing there and still have two rigs drilling in that immediate area.

Stephen Berman – Pritchard Capital

Right, and when you said earlier seven rigs west of the Nesson. Does that include the one Montana rig or is that just in North Dakota?

Jack Stark

That’s just North Dakota.

Stephen Berman – Pritchard Capital

Okay, and one Anadarko Woodford question. I guess it was the Brown well, a couple of months ago, you said you’d gotten it, I believe it was north of 850 in Mcfe in pricing. Are you still getting, are you still getting similar kind of pricing as we move forward here?

Jack Stark

We are Steve, that was on our Ballard well in the Southeast Cana, that’s where we have that real high condensate yield, have over 200 barrels of condensate yield down in Grady County on our wells. Unfortunately we have a little over production rate and that’s what we’re trying to overcome right now. We’re drilling in a more brittle section of the Woodford with the Dana well, which will be completing here in about within 30 days. So we’re pretty excited about that because we did have an exceptionally high gas price there, it’s over 1500 Btu gas, real strong liquid yield. So you get that price.

Up in the Cana field, the Northwest Cana, we are in the 1100 to 1200 Btu gas range getting a good premium but not near as high as we get down a greater county.

Operator

Your next question comes from the line of Joseph Allman.

Joseph Allman – JPMorgan

Jeff, I think you said that you drilled some second wells per 1280 spacing unit in North Dakota. How many of those have you done so far?

Jeff Hume

I think we mentioned eight or nine, that we have done. And what those are just payers where we had either a Three Forks well or a middle Bakken well, and we have come in and drilled a pair to it, that we offset 660, and that’s what we – but we want to have those in those two horizons to have those offset 660 apart and ten we will have eventually a 320 acre equipment spacing, you will have 1320 interval spacing on each horizon.

Joseph Allman – JPMorgan

So you’re saying that you had a middle Bakken producer already and then you came in and you drilled another one in the middle Bakken or you had a Three Forks and you drilled another one in Three Forks.

Jeff Hume

We drilled a middle Bakken well, 660 feet offsetting a Three Forks well. So it’s a staggered but in the other horizon.

Joseph Allman – JPMorgan

So have you tried any where you are drilling in the same horizon?

Jeff Hume

We have not done that yet.

Joseph Allman – JPMorgan

So what are the plans to do that and then further what would be the plans to drill a third well in the same horizon?

Jeff Hume

I think that will be something we will be looking at next year. This year we got two-thirds of our fleet working on acreage that’s undeveloped and we are moving very fast to cover our commitments on leases and get those leases under our production status. And then we will be coming back with some of these rigs and we are working on the density. I think the good news is over in Montana, Elm Coulee where we have higher permeability in the rock, we are down to 320 acre spacing now. In fact our last well we fraced, I was in the field yield yesterday and the guys told me of, believe it was a 24-stage frac; only one of those stages intersected the other two wells. And so you have two wells that produced well over two years, probably three years on either side of it and we have drilled a new well, 24 stage frac and on the pressure recording instruments in the two offsetting wells, we only saw interference on one zone in that area. So if it’s working in Montana, it’s almost a nobrainer that it’s going to work in North Dakota. That’s as close as I can get you right now. I think next year that’s something we will be having on our list of things to do, start proving up the density that we can ultimately develop this resource play on. And right now we are very encouraged that we can develop down to 320s but we just don’t have the proof yet.

Joseph Allman – JPMorgan

In the Niobrara, I guess this is for Jack, so your first well, where will that be and why are you choosing that location?

Jack Stark

Our first well will be down at the Weld County, Colorado, and we have got a position there that’s really about half a way between Noble’s activity down there in the Wattenburg and near the Wattenburg area and EOG’s discoveries to the north. And we have 3D seismic there. That’s one of the drivers for the location outside of it, that it’s in a good neighborhood. So we are using that seismic to guide the drilling that we will do in that area. We will be in the process of getting 3D seismic shot on some of the other projects and get those in the queue for down the road.

Joseph Allman – JPMorgan

You folks mentioned the focus on oil projects going forward. So is Arkoma Woodford is something that you might potentially sell?

Jack Stark

We haven’t considered a sale of Arkoma Woodford and that regard, when you look at the tomb of oil or condensate versus natural gas, you come up with a combination of value here lot of times at the oil or condensate will exceed the value of the gas. So particularly in the southeast area of that play. So that’s a very liquid rich component down there.

Operator

Your next question comes from the line of Scott Wilmouse of Siemans Incorporated.

Scott Wilmouse – Siemans Incorporated

You guys mentioned in the Bakken improving 30 and 60 day rates. Can you quantify these improvements?

Harold Hamm

Certainly. We are seeing from third quarter – let’s just go to second quarter ‘09 to second quarter ‘10, we have gone from having 60-day production rates in the 550 range or – we are in the 550 range now, just under 600. In the second quarter of ‘09, a year ago, we were in the 400 barrel range at 60 days. Our 90-day range change, we were currently in the, again, just under 600 barrels a day, in the second quarter of ‘09, we were just under 400 barrels a day. So we are seeing growth – had almost 50% growth in one year’s time on that.

We talked about this in the past, the number of wells that we complete each quarter is up and down. So the statistics move around, you need to look at averages over a period of time. But we are seeing improvements in the decline rate, that’s not as deep as it used to be and that’s attributable to the additional frac stages. We effectively draining more rock, we are getting better frac placement or placement of profit within the formation and getting better drainage on that.

So I think we are going to continue to improvements and this industry continues to change, frac scheduling and how we treat these wells, we have got a lot of room to continue to improve in the play.

Scott Wilmouse – Siemans Incorporated

And just to clarify, when you say 60 or 90 days, that’s the production rate at day 60 or average over 60 days?

Harold Hamm

That’s average over 60 days.

Scott Wilmouse – Siemans Incorporated

Speaking about rig activity in the Bakken, just from a logistics or staffing level basis, how many rigs could you guys potentially run if economics justified it?

Harold Hamm

Well, as I mentioned, we have acreage position now that we could easily run 30 rigs. Yesterday we were up in the field at – we spent most of our time up in the Norris area, which is about one-eighth of our acreage position. We have six rigs running in that area right now and have a seventh rig moving into that area. So we can very easily accommodate 30 rigs. You could put more rigs than that up there. As we derisk and work at all these different areas, I think we are going to be very encouraged to do that.

And as far as personnel, I might back up to October 2008, we were at 31 rigs then. So I think personnel-wise, we can handle it.

Scott Wilmouse – Siemans Incorporated

With that as a backdrop the potential to increase rigs further in the Bakken, kind of walk me through the decision to enter into the Niobrara, just more opportunistic or diversification, just kind of the thought process you guys had on that.

Harold Hamm

We have worked in that play over a lot of years. We like to say it was there back in early 90s drilling horizontal wells there in the Saddle field, this is before the advent of multistage fracs and that would have turned that whole thing around, although our wells back then inside field where we had fracs or rigs where it’s more economic by far, but still you got to – taking it to a wide spread development had we had that technology at that point. So we like the play developed but that’s, as you know, first of all it’s oil, that’s one thing we liked about it. It’s sweet crude. We see it being a wide spread resource play and it’s something that we felt like would naturally fit our top of play real well.

Scott Wilmouse – Siemans Incorporated

You mentioned Continental tripling in size in the next five years. Is that a specific reference to your production or reserves, or both? Can you just clarify that?

Harold Hamm

All of those above, yes.

Operator

Your next question comes from the line of Amir Arif.

Amir Arif – Stifel Nicolaus

On the eco-pad drilling, I mean you have lower costs. So just curious on the completion side, are you going to be doing anything different on completions, like completing two wells simultaneously or anything else or just logistically that’s too hard?

Harold Hamm

Well, we talked about doing that. Right now the frac crew are spread so thin at there, it would be almost impossible to get two frac spreads at the same time. But in the future as we get further along in development mode, that may be something we do. We have about the potential of doing that. The savings right now is moving frac crew in and being able to – with one setup, you frac four wells. So each rig up and rig down of the frac crew is about a half a day each. So it’s about one day of frac crew time is tied up for each well on a single pad.

So on a four pad environment, I save three days, that frac crew gets three days out of 12 to 14 of actual time that will be on the well. So we are saving that time for the frac crew, so we are making the service contractors crews more efficient if you will by going to that development style.

Amir Arif – Stifel Nicolaus

And that’s where the laterals are at least 5% longer. So is that where you are testing the 30-stage fracs or are you doing that on other wells as well?

Harold Hamm

Well, right now the 30-stage that we did this quarter was in a normal – a single well, which is normal lateral length, just a little over 9000 feet. But we will be adding stages on the eco-pads where we are able to drill along the laterals, be adding a stage or two in there.

Amir Arif – Stifel Nicolaus

Okay. And then just one final question and I think you touched on this more with Joe’s question. On the eventual spacing that you talked about the 320, is that implying one Three Forks or one middle Bak on the 640 or you are talking about for each productive zone, 320 –?

Harold Hamm

I think talking each horizon. So what you will have is four wells across the section or 1320 interval spacing on one horizon. So let’s say the middle Bak and the upper zone, it will have four well bores evenly spaced across one mile. We will also have – below it an offset 660 feet. It would be right in the middle of those, the Three Forks developed 320 feet spacing across there. So it’s kind of like a, if you can visualize a wine rack, how it looks, with offsetting bottling one above the other. That’s how we will have the eventual pattern look across the field.

Operator

Your next question comes from the line of Noel Parks.

Noel Parks – Ladenburg Thalmann

Actually, I hopped on a little late, so my apologies if you addressed this already. But just thinking about the footprint of the Bakken play, considering how much acreage you already have, what’s your appetite for pushing out to some of the frontier of the play where the acreage still hasn’t run up that much but where – we really have very little data. Is that something that you think is worth your time and energy or have you pretty much settled your acquisition areas and that’s pretty much that?

Harold Hamm

Well, I think we have an appetite that is always going to be here and that’s the nature of our company. We continue to want to grow. Now pushing the edge of the play, we push the edge of it and I think we will continue to in the future. Right now we have a very significant area that’s in the core, and as you are well aware of, the core is getting very large, it’s almost going from the Elm Coulee field to the Nesson Anticline and actually farther east through partial. So it’s getting very large, so we are filling that up.

There is now work to the south end of the field along the Lewis and Clark and just above that area, that’s going to be pushing at that direction. And I think you will see work pushing it to the north and west. So, we are going to be participating in all of these areas to some degree. So we still have a strong appetite and we are still going to be looking for opportunities to enrich position in the Bakken. We are very comfortable up there with what we are doing and want to keep drilling at the division.

Jeff Hume

I think the main thing of my point earlier was that the acreage that we have leased over the past six months is 170 some thousand acres, basically has not been in those frontier areas. It’s been and as the play expanded. And so, we haven’t gone out on the edge, there is people out there doing that, waiting for instance with their play in the Three Forks to the south there, and definitely is an extension of the play.

Noel Parks – Ladenburg Thalmann

I noticed since the last press release when you released guidance, it looks like the total growth acreage count is up maybe another 10,000 or something like that. Was that fill-in or is that any more extension on to what you have leased so far?

Harold Hamm

No, I didn’t understand your question. Would you mind repeating that?

Noel Parks – Ladenburg Thalmann

Yes, at your last press release where you increased guidance last month, I think the acreage count was about 806,000. The gross acres, it’s up about 10,000 from there and just wondering where in general you have done your most recent adds?

Harold Hamm

That 10,000 incremental is pretty much – it also west to the Anticline. I mean when you look at the acreage that we have put together here, very high percentage of that has been acreage, but we picked up in new areas west to the Anticline.

Noel Parks – Ladenburg Thalmann

On the Cana Woodford, if I remember right, I think maybe a year or ago or so, the well costs you were looking at there were under six, like around five, seven if I remember, and I think I heard earlier that you are looking at more like $7.2 million. What does that do as far as the price you need for a comfortable return on that play, the gas price?

Harold Hamm

What we are seeing is at that time rigs were plentiful and frac crews were plentiful. That’s firming up very fast, so we were at – we are projecting a $7.2 million cost this time. We are seeing our recent wells are over 7 Bcfe EURs. Back a year ago when we were (inaudible) around $5 million plus, we were looking at 5 Bcf type wells. That was one of the earlier questions where we are going with EUR model here. Our model was currently 5 Bcf but we are demonstrating over 7 Bcf results and I think we will be improving those as we continue to learn more about this play and more about completion techniques as we move forward.

So I think we are pretty much on par with what we described a year ago, the magnitude of the costs have gone up but also the reserves have gone up accordingly.

Noel Parks – Ladenburg Thalmann

So still in that phase, $5 gas range, still comfortable with the economics there?

Harold Hamm

The economics are good. They had very high rate of return there. I mean (inaudible). We feel good with that.

Operator

Your next question comes from the line of Brian Corales.

Brian Corales – Howard Weil

On the Bakken, and I apologize, I jumped on late here, the 30 frac stage versus I guess your standard of 24, do you all see a cost benefit or does it vary by area? What are you all are seeing there?

Harold Hamm

What we are trying to do is sprinkle some 30 stage fracs across our activity spread to see if – to compare that with our 24 stages – to answer that exact question, I don’t have the answer to that. Early time it looks, we just have a few datapoints and that doesn’t really give you the answer. But the early datapoints indicate that we are seeing a little bit better production from that. The key is going to be what does, after 90 to 180 days, on those 30 day wells, do I have a better decline curve or a flatter decline curve than I do with the 24-stage fracs and at what point do we see a diminishing return on the cost of adding those six stages to that new profile.

So my good instinct is we are going to be putting more stages on these wells, just driving through the field yesterday, you see how it really dawns on you how long, a two-mile long lateral is. And 30 stages is just not that much.

The other part of your question is it area dependent. We are not doing area dependent, don’t see any difference in the areas right now. We are trying to apply the 30-stage frac across there. And what we have always done is systematically step ourselves up. We have a lot of wells to drill in this play before it’s over, we want to do it systematically. So I am not out, spending a whole lot of money doing 30-stage fracs or 24 stages, way to go. So we are rapidly building a solid database of 24 stage fracs, we are going to start sprinkling in the 30-stage fracs across the play, the entire field and start comparing that.

Probably early next year we will have dataset on 30 stage fracs. We will be comparing with the 24s and that may be our standard by that time, we just have to see.

Brian Corales – Howard Weil

To follow up on that, can you maybe talk about your current AFEs you’re seeing on the 24 stage or your standard well and then what the incremental cost is for adding the additional stages?

Harold Hamm

We are probably looking at incremental stages in the $70,000 to $90,000 range. So if you use 80,000, if you add six stages, that’s close to a half a million dollars that you would be adding to it those next six stages, maybe a little higher than that. So I have a few more plugs to drill out and a little more cleanup cost at the end it. So $500,000, $600,000, $700,000 incremental cost, so we are going to have to have reserves in a profile to offset that to have a rate of return. I think we can achieve that but we are going to do it systematically and do it in a prudent way. So we are not out wasting money.

Operator

Your next question comes from the line of Irene Haas.

Irene Haas – Canaccord Adams

I have a question on the Niobrara. I guess your view is that the Niobrara play is one continuous reservoir. Just sort of wondering, behind your $2 billion estimate, how much are you assuming in terms of recoverable oil per square mile? And secondarily, do you see any variability within the chalk in terms of porosity and thickness, any sweet spots. What’s the name of the well you are going to be drilling in Will County? Would the lateral be longer than 4000 feet and sort of how many stage frac have you planned?

Harold Hamm

Right now we look it as continuous depositional environment. There is not near enough wells to answer the second part of your question, but we would be able to do this everywhere, but we feel that it will. We will be able to do just from the vertical well control we have out there at this time. Lots of wells have drilled through the Niobrara, have good well control. We have got all characteristics across the entire play mapped out with additional well control, I am sure there will be sweet spots as there is in any resource play as compared to others. But it is a continuous accumulation.

The recovery factor is probably going to be similar to other resource plays. We are going to be in the 5% to 7% recovery of oil in place. We are still very early in development of the play to really be giving significant answers on that. So there is a huge amount of oil in place because it’s a very thick rock, it’s 30 to 100 feet in places and more. So, tremendous amount of rock. Jeff, you may want to put some color on that.

Jeff Hume

We have read a lot of things, I am sure you have read as well. I think Irene you had out some numbers as well. But a million barrels a section is the number that’s being talked about out there, 5% recoveries. And those seemed very reasonable given our experience with these plays. The shale, this Niobrara chalk as Jeff (ph) said is very wide spread. There is going to be nuances throughout the play as there are in all of these plays. But when you step back and look at the big picture on this, you see a whole petroleum system where you are going from a biogenic gas play on the east side to a thermogenic play down in the central portion of the basin down to the Wattenburg area. And so, clearly, we see this across the whole basin based on penetrations and well data that exist today.

So based on our experience, we think there is a real live oil resource play here to be harvested.

Irene Haas – Canaccord Adams

Okay. How long is the lateral of your first well?

Jeff Hume

We are putting an application in for 1280 spaced units. So that gives us about 9000 for horizontal. Assuming that the commission there, it allows us to do that, we will get it done. If not, then we will be drilling a 640, a standard 640, which would be 400 to 500 feet or so.

Irene Haas – Canaccord Adams

Having been one of the first movers in the Bakken, can you just sort of compare and contrast the Bakken versus the Niobrara?

Harold Hamm

Obviously, the zone itself, the makeup of – for most itself, the Bakken consisting primarily of shale, we are out there that that we are working right out there, that’s a vast contrast from what’s Niobrara is.

Jeff Hume

There you have two very distinct shale members that are highly organic that generate that hydrocarbons that are middle Bakken and the Three Forks. And here in the chalk, you got the organics a little bit more uniformly distributed. The zones we are targeting in here will be the more calculus zones, one of those that are more limey and more brittle. But you have essentially this couple of hundred feet of chalk section here that’s got enough organics and it has been thermally mature to be able to generate the oil and gas throughout the play. So there is probably more similarity to this, obviously the Austin chalk and the Eagle Ford then it would necessarily be to the Bakken, because – not only age-wise, but also just their logic makeup and all.

Jeff Hume

And, Irene, I think comparing early Bakken North Dakota versus early Niobrara here. I think what we’re seeing is the coast being real quicker in the Niobrara and we’re seeing IPs from several companies up there across a pretty expansive area. So, I think the initial code maybe broken a little bit quicker.

A lot of that’s because techniques that we’re developed in the North Dakota Bakken are being applied here immediately, the multistage frac techniques are being applied here immediately. So I think we may – the learning curve maybe a little quicker in the Niobrara to get to up the economic speed as it was in the Bakken as you’ll recall it takes several years to really get it to where it is today.

Operator

Your next question comes from the line of Jennifer Jurrius (ph). Please proceed.

Jennifer Jurrius (ph)

Good morning, guys. I just have a couple of quick questions. Pardon me?

Harold Hamm

Certainly, go ahead.

Jennifer Jurrius (ph)

The first question is mainly basically about some of your other plays that aren’t going to be in your core area, it sounds, but just looking for a little guidance projections on your Red River and Mid-Continent production.

Harold Hamm

Well, the Red River, we’re continuing – that’s still a core asset for us. We didn’t talk about that, but it is – we’re bouncing around 15,000 barrels a day net production today. We have two rigs working in the Red River units. We see in the future, our Red River teams have quite a bit of drilling to do in there to add reserves and production into next year, we’ll be announcing that later this year.

One of the rigs is working Cedar Hill, we should have it finished development on 320-acre producing spacing or a 160-acre absolute well spacing we have – as you’re aware we have an alternating water line drive in that field. Production continuous to grow in that field as we drill new.

You’re aware we’re converting the old producing wells to water interjection wells as we add – increase that density of new wells on the either side of it. So we are seeing good growth in there. The medicine pole hill, some Buffalo units, we have a rig in medicine poll hill currently, we’ll be moving that down into Buffalo units probably next quarter. And we continue to build a position of – or continue to develop the core of those two units. And in Buffalo, we think we can extend the field to the north.

We’ve put acreage together to the north and west of the field. And part of our work in the future into this year and early next year will be to extend that field to the north and we’ll just see how that goes. We’re very excited about the Red River.

Jennifer Jurrius (ph)

Okay. And why was there such a decline do you feel in the Mid-Continent region for this quarter?

Harold Hamm

I think it’s just rig activity. We moved some of our dollars in the Arkoma over to the Anadarko and moved – and up to the Bakken this year as compared to last year. We have less rigs running.

It is just natural decline. We didn’t maintain the rig count to the level we have in the Arkoma a year-ago. So we’re going to suffer a little with that. That’s going to quickly turnaround as we ramp up our activity in the Anadarko Woodford later this year and into next year, so that’s a short-lived phenomenon.

Jennifer Jurrius (ph)

Okay. That’s all I have for you guys this morning. Thank you.

Operator

Your next question comes from the line of John Daily (ph). Please proceed.

Harold Hamm

Good morning, John.

John Daily (ph)

Can you just talk a little bit about how you feel like you’re positioned right now with new plays? And, obviously, with the Niobrara coming to fruition, do you still have new ventures activity ongoing or do you feel that you’re pretty much done at this point?

Harold Hamm

We’ll always be looking. We’re an exploration group and have a strong exploration team in presence and we’re going to be looking around us all the time. But, obviously, we’re going to take advantage of the place that we know first. And the Niobrara was certainly one of those, and at better criteria, it’s oil and we know how to do that horizontal resource development and oil play. So we’re going to keep looking. But, right now, we feel like we are awfully well positioned in this company for future growth.

John Daily (ph)

All right. And then in terms of value recognition for the growth or for the tremendous acreage positions that you’ve put together, many of your competitors are engaged in joint ventures or farm-outs or things of that nature. How do you look at those philosophically? And how do you look at those as possible tools to add value to the shareholders as you kind of work your way through this tripling of reserves and production over the next five years?

Harold Hamm

That’s a good question. I appreciate it. We’ve taken a different approach. Our approach here has been to build equity and value for our investors. We haven’t done joint ventures. We usually capture the value within the company for those investors we’ve done that in a very good manner. Not overstepped to the point that we can’t develop it in the future. So we have a plan to do that.

And as we’re tripling our growth over the next five years comes from, yes, we’ve stepped up to do that and something we can accomplish and we’re seeing that value recognition. Finally, in some of these plays, we’ve seen some of these lease and sales up there – for instance in this not particularly prime areas as we have in Bakken, that’s (inaudible). So this is an acreage that we picked up at far less than that, as I indicated earlier.

Harold Hamm

You’re welcome, John.

Operator

Your next question comes from the line of Gil Yang. Please proceed.

Harold Hamm

Good morning, Gil.

Gil Yang – BofA Merrill Lynch

Good morning. I wanted to ask about the growth tripling or the volumes and reserve tripling, do you see that? What allows to you grow faster than you had been able to grow before? Are the margins better than what you had historically or is the access to capital greater that you can invest more to get you up to that target quicker?

Harold Hamm

Well, we like the pricing environment that we’re in now with $80 plus looking forward. That’s much better pricing environment than we’ve had in the past. We’re doing as much job – better job of protecting at our bottom line with our hedges that we’ve got in place and protecting the drilling activity that we’re ramping up with.

Also, the well productivity that we’re seeing particularly in the Bakken, where we have so much acreage, and as well as in the Anadarko Woodford, we’re seeing that production be very, very substantial, so we’re excited about that. And then, basically just to gearing up to the point that we are and we feel like they will maintain a momentum going forward that we started back in 2008.

Gil Yang – BofA Merrill Lynch

All right. Well, you have been in this business a long time. What would be – what worry that would derail your ability to get to that goal?

Harold Hamm

Well, several things. I have been in this business a long time. We always look up for the pit balls. And certainly pricing, governmental regulation, a lot of things, tend to worry you, and you involve yourself in all those, we have with hedging, protect yourself, in that regard.

As far as the governmental aspect, I feel much better in the last few days that I have in the past, in the kind of wells clubbed, lot of these Gulf was between that, so some of the negative spotlight is off of our industry finally. We’re seeing an industry – energy bill, but I don’t think it’s going to harm as greatly going forward, so we feel pretty good about that. So, yes, I have been in this industry a long time and I feel good about what we’re doing here at this company.

Gil Yang – BofA Merrill Lynch

Okay, great. Are you worried about costs slowing your ability down to get there, to get to that goal?

Harold Hamm

We do, but then somewhat, but you control a lot of that have been there early and our ramp up appears to these plays we saw that trend going and we responded, got ahead of the curve on it, we worked with some awful good contractors and they’re able to build equipment as we need it and put work and they’re highly rested and doing just that. So I don’t think cost will get a hand on this.

Gil Yang – BofA Merrill Lynch

Thanks. I appreciate your insights there. With respect to the Bakken well improvements that somebody asked earlier, you mentioned a number of different things in terms of the decline rate being better. Was lateral length one of the components that contributed to the stronger 60 day to 90 day well performances?

Harold Hamm

It is. Lateral length is a factor. I think the biggest factor, however, is the density of the multi-stage fracs and has in shorter intervals, new rock, smaller capacity fracs, the now sand that we’re putting in it, the (inaudible) and all those things contribute and I think that’s the biggest factor there.

Gil Yang – BofA Merrill Lynch

Okay. And then but the eco-pad, I know that it’s sort of a four well pair drilled in two different directions, do you anticipate any – other than the costs, do you anticipate any synergies from having the well, the pairs of wells being drilled and fraced simultaneously from a frac energy perspective or anything like that?

Rick Muncrief

This is Rick Muncrief. I think one of the things that you will see that’s a synergy is a shorter cycle times and actually bringing the volumes on quicker than – with the four eco pad locations, comparing that to four traditional single wells.

Gil Yang – BofA Merrill Lynch

So you don’t expect that the fracing will be any different in terms of putting more energy on the rock and fracing the rock more effectively?

Rick Muncrief

Well, it very well may in the future. Right now, we’re not where we can simul-frac wells like we did in the Arkoma. Our team has talked about that, doing that in the future. I’m sure we will try that at some point in the future.

We haven’t done that yet. We’ve just finished our first four-well pad, where we’ve fraced a middle Bakken well and a three forks well in two different spacing units. We will be flowing that back or cleaning plugs out and flowing that back here next week. We just finished it yesterday, in fact.

So I really don’t have the information to tell you, has it improved it or not, it would be great if it would, and there is a good possibility that it will, because we did concentrate a lot of energy in both of those well bores, 660 feet apart laterally, and roughly 50 feet apart horizontally – or vertically.

So it’s just too early to tell. That potential could be there, I think putting more energy into the rock and smaller area has been a proven concept that works. We’ve done it in the Arkoma, and I know they’ve done it down in the other plays. So I think that’s something that may come to fruition in the future and we’re just not quite there yet to give you an answer that’s meaningful.

Gil Yang – BofA Merrill Lynch

Okay, thank you.

Operator

Your next question comes from the line of Subash Chandra. Please proceed.

Subash Chandra – Jefferies & Co

Yes, hi, good morning. If you covered this, I apologize. But in Northeast Cana, I guess there is a bit of an oil rim up there, maybe a rich condensate rim, and if there is an update on activity. And then, secondly, to beat this Niobrara horse to death, but a couple of questions there. As far as geo pressure, how important will that be? And does it exist throughout?

And second, I guess we’re hearing, as you said, the DONNA log is probably closer to Eagle Ford than it is to a specific bench like in the Bakken. But we’re sort of hearing that maybe nature may have to play a larger role here through natural fracturing, so it won’t be entirely offset and compensated by frac stages and lateral length, and if you can comment on that, if you believe that to be true, that you do need to see natural fracturing here in ways that you perhaps don’t. And also, evidence of structures, if you need to see structures here, where perhaps in the Bakken you don’t.

Harold Hamm

We’ll start out with Jack.

Jeff Hume

Okay. On the Northeast Cana, we’ll go to your first question, we’re seeing a higher in the north – going Northwest of Cana, we are seeing – and in Cana itself as you move to the Northeast all along that bench going out there, we’re seeing higher liquid content as you go up.

As you’re going to the South, we’re seeing the liquid content a little bit lower in the section down at the equivalent depth that we would be on the brown well for instance in the Northwest depth-wise down at Brady County we’re seeing over 200 barrels of condensate for me. And so we’re going to see going up depth all along the North and Northeast Rim. And as you move around with the Southeast side, as you come up out of Anadarko Basin, you get shallower.

We’re going to see higher condensate yield. That’s a plus and the fact that we have better pricing, it’s going to be a minus, and the fact it’s going to be lower productivity due to the liquids component in the rock. But, thus far, we’re seeing very good productivity where we’re working in the 20 barrels to 35 barrels a condensate per million range.

I know other operators have drilled some wells with higher liquid yields just to the East or Northeast of the Cana field itself and looks like they’re getting good liquid gas ratios in there. And I’ll hand it off to Jack to talk a little bit about Niobrara.

Jack Stark

Yes, Subash, hi, this is Jack.

Subash Chandra – Jefferies & Co

Hi Jack.

Jack Stark

Good questions regarding the Niobrara. We’ve asked ourselves the same questions. How much of this is matrix? How much of this is natural fractures? Historically, the production has been through natural fractures out there. But now we’re seeing evidence that the technology that we’ve seen applied in other resource plays is now turning on the matrix. And so, I think you’re going to find in this play that you’ve got both aspects going. You can be in some more structured areas and clearly get natural flow out of these wells.

There are some wells out there being completed that are un-stimulated, but we had the same thing in the Bakken and if you remember that and we still see those happening out there. So those are really nice when you run into them, because you get some excellent flow rates. But the real large value out here is being able to harvest that matrix and we do velocity developed in that B bench (ph) of the Niobrara. And we believe from what we’re seeing here that going in and applying this new – the evolving horizontal and multi-stage frac combination technology there, we should be able to have a much more widespread development.

You can look at resistivities, lot of people map those across to – and they vary, but there’s also mineralogical things and in fact the resistivities are near. And so, good questions, there’s lot more information that come out and the knowledge we gained on this place, we get on to road.

But, one thing is, there is a lot of what’s called listric faulting within the zone itself here, a little bit unique to some of the other plays and so 3D seismic is valuable to use as a geosteering tool and also maybe a hazard surveys as I guess we call them just to avoid some of the larger faults.

But – so – and as far as geo pressuring is concerned, how important is that? I’d love to see higher pressures always. In the Niobrara we’re still evaluating the degree to which we’ve any geo pressuring exist in here. But, right now, based on the results we’re seeing, we see whatever it is, it’s sure looks like it’s enough so.

Subash Chandra – Jefferies & Co

Two follow-ups there. Sticking to the Niobrara, how patient do we need to be to where you are confident you’re tapping the matrix versus the natural fractures, is that like monthly production for? And then on the Cana, any update to the Devon well up in that oil window? I think it may have come on at fairly good IPs and if you feel like that’s a worthwhile type play to pursue up there?

Jeff Hume

Okay. The matrix versus fracturing in the Niobrara, I think it’s going to take time-wise, I think we’re going to have to see a – six months of productions to get a feel for what that’s doing. We had quite a bit of experience in the silo field and it was highly fractured in that area.

In drilling wells, you would effect a well over a mile away from you while you’re drilling it with a fluids you’re losing as we expand across the entire depth position of Niobrara, we’re just going to have to get some wells completed and those decline curves will show you that probably within six months, what type of production you have and it will have pretty quick. And also, inter-well fracture interferences as we start drilling more wells in the play, it’s very, very young play, not a using the new techniques. But we are very, very encouraged by what we’re seeing so far.

Back to Cana and Northeast Cana, I don’t have any more information on their well other than that early reports that came out that it was making high oil content. I don’t know Jack, if you’ve heard anything about – I don’t believe I don’t have that information Subash.

Subash Chandra – Jefferies & Co

Okay, that works.

Jack Stark

Subash.

Subash Chandra – Jefferies & Co

Yes.

Jack Stark

Subash, I was just going to mention too and you’re probably aware of this. But in that Niobrara play too, there’s also some added upside to the play when you consider we’ve got the Kodel (ph) out there, the Green Horn, and also the Carlyle Shale that are all very potential objectives out there as well. And, obviously the Kodel being well developed and harvested it down in (inaudible). But it’s not contained or limited just to that area. So, anyways, there’s outside of just the one single B benches, I think a lot of people are focusing on and here there is other opportunities as well.

Subash Chandra – Jefferies & Co

Okay. And I’m just going to sneak one last one in, I hate to hog the call on Niobrara, but just finishing up on Niobrara, but are there water zones that we need to be concerned about and what are the frac barriers that are dominant throughout the region?

Jack Stark

I’m not at this point not aware of any water zones that we would have to be concerned with. We just see – we just don’t see evidence of that. At least, we have not at this point so.

Subash Chandra – Jefferies & Co

Okay. And so I guess you can just frac away?

Jack Stark

Yes, and we believe so. And as far as frac barriers are concerned, I think that one of the things as Jeff had mentioned we’re going to – or Harold had mentioned, these multistage fracs, what we’re doing is, we’re drilling of a long lateral here, including smaller stage fracs that don’t frac out of zone, actually contained in zone and that’s what the benefit that we’re seeing from these higher number of stage fracs is you’re not putting as much away in say in an individual zone, but you’re actually fracing and stimulating and connecting with more rock. So, anyways, I think that technology will really help us out here as well. But Niobrara is plenty thick here to keep I would think for paying the price.

Subash Chandra – Jefferies & Co

Got you. Okay, thank you very much.

Harold Hamm

Yes, thanks Subash.

Operator

Your last question will come from the line of JT Schultz (ph). Please proceed.

JT Schultz (ph)

Hi, guys. Thanks for all the color. I’m not sure what I got left to ask here but I will try one thing here on the Woodford. I guess when you get up to seven rigs in the year, can you just talk a little bit about where you will try to focus most of your drilling as you balance? I think what you had said, the higher productivity versus (inaudible) and just specifically on some of the Northwest Cana wells that you come out with. And then still fairly gassy wells, I guess as you learn more, you expect the liquids portion to creep up a little bit there.

Jeff Hume

Okay. As we ramp our rigs up, the bulk of those will be in the Northwest Cana portion of the field, the Southeast Cana will be working one or more rigs. We have two key wells, the Dana that we’re drilling now and the ones subsequent to that we think will really open that area of the play up. So, right now, the plan is the bulk of those rigs be working in the Northwest Cana.

Now, the oily portion of the Anadarko Woodford, I think you will see over the next year, year-and-a-half, continued push up all across the play into the oilier region of it to test productivity of the rock in those oilier sections. And right now we’re seeing our sales in several other operators of doing that. So I think you’ll see that continuing. I think it has potential to move quite a ways up. Yes, but, time’s going to tell if that holds true or not.

JT Schultz (ph)

Okay, great. Thanks, guys.

Operator

I would now like to turn the conference back over to Mr. Hamm for closing remarks.

Harold Hamm

Again, I’d like to thank everybody for joining us on the call today. We know there are huge other companies reporting this week. We are looking forward to providing greater detail on all of our opportunities in these plays and depth at our Investor Day in Oklahoma City on October 12th. So we look forward to seeing you then. Thank you very much.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.

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