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Continental Resources (NYSE:CLR)

Q2 2011 Earnings Call

August 04, 2011 10:00 am ET

Executives

Jeffery Hume - President and Chief Operating Officer

Harold Hamm - Executive Chairman, Chief Executive Officer, Member of Nominating/Corporate Governance Committee and Member of Compensation Committee

Jack Stark - Senior Vice President of Exploration

Unknown Executive -

Analysts

Joseph Magner - Macquarie Research

Subash Chandra - Jefferies & Company, Inc.

Scott Wilmoth - Simmons & Company International

Hsulin Peng - Robert W. Baird & Co. Incorporated

Jason Wangler - SunTrust Robinson Humphrey, Inc.

Marshall Carver - Capital One Southcoast, Inc.

Unknown Analyst -

Noel Parks - Ladenburg Thalmann & Co. Inc.

Operator

Good day, ladies and gentlemen, and welcome to the Continental Resources Second Quarter 2011 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, and then we'll be able to have a question-and-answer period. Other members of management are available to answer your questions. Now I will turn the call over to Mr. Hamm.

Harold Hamm

Good morning, everybody. Thank you for joining us on our conference call this morning. Continental reported outstanding performance under challenging circumstances for the second quarter of 2011. We generated solid production growth, and we're on track to achieve our goals for the year. This all is made possible by the talent and commitment by the Continental team to overcome adverse weather challenges up there in that area even under very tough conditions this winter.

Our second quarter production grew 29% to 53,984 Boepd. We continued the growth momentum that we began in 2010 and the first quarter of 2011. We estimate that July production was 61,000 barrels of oil equivalent per day. And during this last week, we estimate 62,000 Boepd. So the third quarter is looking very strong. Net income for the second quarter of 2011 was $239.2 million or $1.33 per diluted share, an increase of 135% over net income for the second quarter of 2010. This reflected an after-tax unrealized gain on mark-to-market derivative instruments of $143.4 million and an after-tax $11.9 million property impairment charge. Without the combined effects of the non-cash unrealized derivatives gain, an impairment charge and a small gain on sale of assets, our clean earnings were $0.60 per diluted share. We reported EBITDAX of $285.6 million for the second quarter, a 31% increase over EBITDAX for the second quarter of 2010. Strong cash flow and ample availability under our revolving credit facility have us positioned very well for continued growth.

At this point, I'd like to drill down with more detail on the Bakken. You've seen over the past year consistent improvement in our well results in the Bakken, and this trend continues today as we demonstrated in the last night's press conference. Based on press release -- based on historical results, we raised our estimated ultimate recovery model to 603,000 barrels oil equivalent per well in North Dakota compared with the previous EUR model of 518,000 Boe. The key factors contributing to the 16% increase are advances in well completion technology, including additional frac stages and profit use, which have continued to elevate the production curves on our wells. Secondly, as we explore and de-risked new areas of our acreage, we're seeing the quality of that acreage in our well results. Geology, of course, plays a huge role here.

Our 518,000 Boe EUR model was based on a group of wells with an average of just over 20 stages per well. The new model is based on an average of just over 24 stages per well. Today, our standard design is 30 stages and basically that's a minimum amount of stages that we're using. Bakken well results continue to improve in the second quarter. We completed 34 gross 18.2 net wells as operator in the quarter, and their average initial test period production was 1,188 Boepd. As we noted, our top 12 North Dakota operated wells in the quarter ranged from 1,400 to 2,240 Boepd in their initial test periods. These are our great, great wells.

Some of our strongest results in the quarter involved a 4-well Carson Peak-Morris ECO-Pad project. The 2 Carson Peak wells produced at almost to 2,240 Boepd each in their initial test periods. And the 2 Morris wells in this ECO-Pad project, one tested at 1,917 Boepd and the other yielded 1,400 Boepd, also a very good well. So not only are we saving 10% per well on average on our ECO-Pad projects, we're also seeing outstanding production results with these ECO-Pad wells.

This was continued in the current quarter. In late July, we completed the Debrecen 1-3H, with a 39% working interest well in Stark County. The Debrecen 1-3H tested in early production at 1,667 Boepd, flowing at 2,052 psi on a 24/64 choke and qualifying it as Continental's strongest well to date in the Normandy prospect area. The company has 103,000 net acres in Normandy, which covers part of Billings, Dunn and McKenzie and Stark counties.

Most of our Normandy drilling was back in the early -- very early days in North Dakota some 67 years ago, and now it's seems like we're just getting started. Early results were not impressive in Normandy, so we're very pleased to see an excellent result in new wells using today's advanced technology and developing down into Three Forks instead of the thin Middle Bakken formation that's present there.

Now let's look at Oklahoma Woodford operations. In the second quarter, we completed the Lambakis 1-11H discovery well in the Southeast Cana portion of the Anadarko Woodford. We own a 98% company working interest in Lambakis, which flowed 5.4 million cubic feet per day and 160 barrels oil per day in its initial test period. The Lambakis is 25 miles south of previously known horizontal Woodford production. So Continental had once again expand the scope of the Anadarko Woodford play in the other direction. We own 15,000 net acres around this well and about 90,000 net acres total in the Southeast Cana area. These 2 new discovery wells, the Debrecen in Bakken's Normandy area and the Lambakis in Southeast Cana, are very important good news for the company in terms of the job at each play. And Jack Stark is here with me this morning to discuss this in more detail, if we need it, in the Q&A period. So let's move on to our major reserves.

In the first half of 2011, we increased proved reserves 15% to 421 million Boe. I might add this is based on our internal valuation. Continental's midyear report was prepared by some 12-month unweighted average price of $90.09 per barrel of oil and $4.21 per Mcf for natural gas and further adjusted for location differentials.

Continental is clearly building net asset value as part of our 5-year plan to triple production and reserves. Not only are we building proved reserves, we're accomplishing this in 2 of the hottest [indiscernible] plays in the United States, oil-rich Bakken and liquids-rich gas Anadarko Woodford, where we have decades of developmental drilling ahead of us. By the way, we continue to expand our land positions in the Bakken and Anadarko Woodford. Given a combination of industry factors, we are finding opportunities for strategic lease acquisition swaps and exchanges to obtain operational control, as well as conventional leasing opportunities. We expect these lease hold opportunities to continue.

I'd like to note one other important announcement, for several reasons that we've listed in the release last night, we have increased our 2011 capital expenditure budget to $2 billion, with 86% of incremental spending focused on drilling and related operations and the rest allocated to lease acquisition. We also raised our production growth guidance for the year to a range of 36% to 39%. This will enable us to increase our total operated rigs in the Bakken and Anadarko Woodford this year.

Obviously, it helps us a little with 2011 production growth but the primary impact will be on production growth in early 2012 and beyond. Our strong growth this year has us firmly on track to achieve the goals in 5-year plan list established last October. The goal was to triple our production, improve reserves from year-end 2009 to year-end 2014.

So to sum up, we'll continue to keep Continental on a high growth profile and we're even accelerating that just a bit through the next 6 months. But before starting our question-and-answer period, I'd like to address accidents that occurred in last July -- in late July on the Beaver Creek 1-36H well in North Dakota. Three men were injured and a rig was partially destroyed. I've been in business 44 years, and it's the first time that we've had an accident like this on the CLR operated well side. There's a positive report on the 3 men's medical progress, Tuesday, in Bismarck Tribune, but please join us in keeping their full recovery in your thoughts and prayers.

And with that now, we're ready for the Q&A period.

Question-and-Answer Session

Operator

[Operator Instructions] We do have our first question and it comes from the line of Marshall Carver.

Marshall Carver - Capital One Southcoast, Inc.

On the EUR rates, is that -- I assume that's just Bakken wells. Is there any read through to the Three Forks wells in North Dakota on that EUR increase?

Unknown Executive

That increase is a mix of our average of both Three Forks and Middle Bakken wells. We take the entire population of wells and that's looking in arrears across our acreage spread in North Dakota. So that's an average of all completions.

Marshall Carver - Capital One Southcoast, Inc.

Okay. But how many of the completions in the last year were Three Forks versus Bakken?

Unknown Executive

We're probably running in the 50% range. We drill about half our wells in the Three Forks and half in the Middle Bakken.

Marshall Carver - Capital One Southcoast, Inc.

Okay, that's helpful. Another question. On the -- you've had a quick production ramp up from 2Q to July. About how much of that is due to new wells coming on line versus -- did you have some production that was shut in that then came online or is that new wells in the July increase?

Jeffery Hume

We're going to say the lion's share of those were new wells. We did have some wells that had been shut in or had been constrained. And the other thing you're starting to see there is the fact that we have had some infrastructure build out, especially on the gas side, that allowed us to open some wells up.

Marshall Carver - Capital One Southcoast, Inc.

Do you have a feel for 1,000 barrels a day that was shut in and has come back or not?

Jeffery Hume

Although it was actually shut in, we were not able to move the oil. It was probably in the 1,000 barrels a day range.

Marshall Carver - Capital One Southcoast, Inc.

Okay, then one last question for me. On the Niobrara well, do you have the cost on that and could you give a rate or do you not want to give rates on that?

Jeffery Hume

Yes, the total cost on Niobrara well was $6.5 million and the well is currently in the 10 barrels of oil a day range and some water being associated with it. So that's why we're evaluating it.

Operator

Your next question comes from the line of Gil Young.

Unknown Analyst -

Just following up on the last one of your answers. So when you guide infrastructure that lets you open the wells up, is that part of the reasons for why the IP rates that you listed were a little higher than -- on average than in the previous quarter?

Jeffery Hume

No, IP are wells are the same everywhere whether we have a gas connection or not, and that's -- we're not just pulling the wells real hard. If we look -- drill down and looked at those, most of those wells are drilling or producing initially between 2,500 and upwards of 3,500 psi pressure. So we're holding quite a bit back on those. If we really crank those open and brought all the extra equipment, you'd require to safely flow those at higher rates they could go. But what we try to do is maintain a safe rate for our production equipment that we will be producing through without bringing extra equipment out and flowing those wells. So we're just seeing good consistent results across the field and improving over the quarters. I think part of that is just the frac technology we're applying. As Harold said, we're putting more stages on the well and we're -- this past quarter, we probably averaged 25, 26 stages and now we're kicking that up to 30 stage average per well. We're going to do all of our wells a minimum of 30 stage. We feel that's really giving an improvement opening this tight rock up.

Unknown Analyst -

If you could flow those wells a little bit more openly, how much -- and I'm not sure what the right number would be. But if you let them flow a little bit less constrained, could you get up to -- could you both produce IP rates 2,500 to 3,000 barrels a day or is that too high?

Jeffery Hume

No, you could easily do that if you open these wells up. As I said, we're between 2,500 and 3,500 pounds flowing pressure on most of these wells when they're flowing initially. I mean, they just have very high flow rates, and we just don't feel it's to anyone's interest to just pull them that hard at the beginning. And there is some safety issues because you have a tremendous amount of fluid going into temporary equipment.

Unknown Analyst -

For the EUR guidance, did you -- you gave a single point number of 600,000 barrels of oil. But can you give us some maybe colors if you took fixed smaller field size regions, what the ranges of the different regions would look like in terms of individual EURs for those regions? Just to give us some idea of the distribution of regional performance?

Jeffery Hume

Well, there is a variation and there's variation within a region itself. So if took a geographic region and broke it down, it's easy to see wells within a couple of miles from one another having a variation of 100,000 barrels. So that's why we look across the board and give 1 model and that's what we will deliver. And that may be why we have a maybe a slightly lower model than others because they have only 1 area that they're producing and they just report that area. But across the entire play in Continental, I'll remind you, has acreage across the entire play. North to South, East to West, that's our average. So that's pretty much a reflection of what the Bakken capacity is and our acreage capacity is.

Unknown Analyst -

All right, then. Okay, so 2 points. One is that 600,000 is applicable to your entire 600,000-acre North Dakota Bakken?

Jeffery Hume

That is correct.

Unknown Analyst -

Okay. For the second point, I was just trying to get a sense of how much variation is there. Are we talking about the standard deviation of field type EURs? Is it plus or minus 100,000 from that 600,000 or it's a plus or minus 200,000 from the 600,000?

Jeffery Hume

I'd say you'd have a 200,000 variation, plus or minus.

Unknown Analyst -

Okay. And then the last question about that is just the 600,000 based on the -- I'm sorry, I didn't quite understand what you're saying. Is it based on the 24 stages or the 30 stages of frac?

Jeffery Hume

It was based on the mix of wells that was in the model. And looking back, I think that's probably going to be around 24.5 to 25 stages average on that.

Unknown Analyst -

So there could be some upside if you average in 30 stages?

Jeffery Hume

Absolutely, that's our plan. But we always report trailing factual EURs, not what we hope to have.

Operator

Your next question comes from the line of David [ph].

Unknown Analyst -

Jeff, just wanted to confirm. The $8 million well costs, that's heading forward and you're still thinking 40% ceramic, 60% sand for your Bakken North Dakota wells?

Jeffery Hume

That is correct. That's what we're doing and that changed. We were running around $7.8 million for the 30-stage job, and we've just seen inflation walk that up to there and we feel like that's a solid number for the remaining year.

Unknown Analyst -

Okay. And then as you think about the total company, one of the things as you've increased your capital spending trying to think about what is the base decline for the company first year and second year, and then kind of a dollar per flowing barrel of capital adds. So can you talk about what is your base decline on low capital if you got year 1, year 2 in your PDP base?

Jeffery Hume

I have not looked at that. I need to look at that to give you an honest answer. Quite frankly, I have not looked at the PDP runoff on that, but I can sure get that for you.

Unknown Analyst -

And do you think about -- you talked about 2012 production being driven more by the $2 billion of CapEx. Just reconciling, originally you had about a $1.4 billion budget for 30% growth this year. Now you had a $2 billion budget for the, call it, 37% growth. How do you think about that differential between lot more capital, but not that much more growth? And then how should that roll into '12 or an exit rate?

Jeffery Hume

Our original -- our budget was $1.75 billion for the 35% to 37% growth.

Unknown Analyst -

Okay, 30% growth was $1.36 billion originally.

Jeffery Hume

That's correct, back in October of...

Unknown Analyst -

Right.

Jeffery Hume

Okay. The entire thing is right now we're raising our capital for the second half of the year. And part of that's going to be a carryout going into the next year. We're bringing more rigs in and as Harold said in the Woodford, we'll be bringing rigs in, in the first quarter in the Bakken and improving that. That means I'm preparing locations this fall for locations -- for drilling in the Bakken next spring and our entire net carry in, carryout is ramped up to probably in the $175 million range. So we're going to be carrying some -- doing some work in the fourth quarter -- third and fourth quarter, that would be carried into next year. So it's growing. Our operational footprint if you will for even -- for very strong results in 2012, which we have not announced yet but most people are modeling growth in both the Bakken and the Woodford as we move forward.

Unknown Analyst -

And with that carry in, does that imply just kind of a run rate of capital spending then at about this level? You're not going to see a drop in 2012 because you've accelerated $175 million of CapEx. So just continue to roll forward the program, it's not like you built the pads and now you're not going to build new pads or anything like that?

Jeffery Hume

No, we're going to have an ever-increasing rig count as long as we have a solid commodity market. We're going to continue to do that. We have a world class inventory of opportunity, and we'll continue to accelerate on that within guidelines of ability to execute the plan and cash flow.

Operator

Our next question comes from the line of Scott Wilmoth.

Scott Wilmoth - Simmons & Company International

You guys mentioned in the press release about the potential of deeper Three Forks zone below your existing Three Forks zone and taking 5 cores. Can you talk about what you've seen in those cores and how dispersed are those cores across the play?

Jeffery Hume

Scott, this deeper tense is called the Charlotte 2-22H and is located west of the Nesson Anticline out in sections 22 and 15 of 152 North 99 West. And the Charlotte is drilling ahead right now. And we're targeting a layer of oil bearing dolomite that is found about 50 feet below our traditional target in the top of the Three Forks. And what's significant about this obviously is that it can -- has a potential to demonstrate there's added reserves to be recovered from these deeper zones in the Three Forks. To date, really all of our drilling has been confined into the upper 20 feet to 30 feet of the Three Forks formation. And from our regional studies, we know that the Three Forks gets up to about 270-foot thick. So that begs the question, how deep does the oil saturation halo from the Bakken extend down into the Three Forks. So to find out, we went ahead and cored the Three Forks from top to bottom in 5 wells this year. And these cores extended to -- from basically north to south about 115 miles from Divide County on the north end and Stark County on the south end. And what we found is really quite remarkable. We found that the Three Forks contains 4 benches of inter-bedded oil-saturated dolomites that extend all the way down to the underlying miscue anhydrides in each of these cores. And I really need to be clear here. I'm not saying that the whole Three Forks section was oil saturated, for instance, in the Charlotte core that we took right where we're drilling our test now. The Three Forks was 220-foot thick and contains approximately 115 feet of oil-bearing dolomites: 30 feet in the first bench, 22 in the second bench, 30 feet in the third bench and 32 feet of oil-saturated dolomite in the fourth bench. So these benches from our studies vary across -- they vary in thickness across the basin. But just for the sake of this discussion here, say they average in the range of about 50-foot thick. And the first bench historically has been our target of drilling out here, and it's proven to be very uniform and quite widespread. The second bench from our studies looks to be equally uniform and widespread in its development, and so that's part of the reason that one is our first test that we want to take in a lower bench. The second bench lies about 40 feet to 50 feet below the first bench, and it's underlined by our third and fourth bench. And those benches are not as uniformly developed, but do contain large amounts of oil-saturated dolomites. So our Charlotte test is testing the second bench, which contained about 22 feet of oil-saturated core. And really in the end, what all this really means is that there's more oil in place in the Three Forks than we had previously perceived and this has got to translate into increased recoverable reserves for this field in the future.

Scott Wilmoth - Simmons & Company International

And just following up. If the second bench is successful, that is not going to -- that could be additional locations. It's not -- you wouldn't hit both the first and second bench with one well?

Jeffery Hume

That's our expectation at this point. It needs to be drilled to be proven. But we will probably also -- you'll see us in the future going and testing these lower benches, the third and the fourth, where we feel that they are most prospective.

Scott Wilmoth - Simmons & Company International

Okay. And what's the timing on the Charlotte well ongoing? And is there any additional cost aside from just slightly lower depth on these wells versus traditional wells?

Jeffery Hume

No, there's no difference in cost here. We didn't take a core and this one we'd already cored in the Charlotte #1 well. And as far as timing, it's drilling. We're probably at kick off point here today, and we'll be cutting into the zone here probably within the week and have it [ph] here with Rick in a couple of weeks.

Operator

Your next question comes from the line of Noel Parks.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Just a few questions. I wasn't sure whether to make anything of sort of the BTU variability in the Southeast Cana. I noticed that the pricing that you seem to realize, I think in the most recent period in the Lambakis well, seems to be a little lower than the liquids prices, or I should say it like it's on equivalent basis that you've got in terms of some of the earlier wells. Can you tell me little bit about that?

Jeffery Hume

I think that's just -- what we're seeing there, Noel, is just the different gas contract -- that was a realized price on that contract, which was to an existing gas market. As we begin drilling down there, we'll negotiate and we'll contract for that area. The entire Southeast Cana area because we're just drilling spot wells and they are 25 miles apart. Obviously, we don't have one blanket contract over there so we're marketing into existing infrastructure. So you're going to see some variation on cost. Back to the BTU, we're seeing consistently high BTU in that area and high liquids. So I think that was our point with the $3 and I think $3.90 [ph] price, where we're seeing over 650 into that market that we went into. I think we're going to have a good uplift in value especially as we begin a drilling program down there. We've got -- we feel we're drilling another well right now in that area as we get a second well in there, we'll consider that area, de-risk and go into full development. At that time, we'll negotiate a contract that is more favorable to the working interest owners. But until you get that program started, you're pretty much tied to the existing infrastructure and what contracts are in that area at the time.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Great, that's helpful. Thinking about infrastructure, if I remember right, you -- I'm sorry if you mentioned this earlier, I've been popping on and off a bit. Remember there is new infrastructure coming on in the Northwest Cana area. But I was wondering for the wells that you reported in the quarter, how pipeline constrained were the well rates that you gave in the Northwest?

Jeffery Hume

Well on certain wells, we have probably a 30% to 50% constraint on deliverability early days production, the first 6 months production just due to infrastructure. We have entered into a contract for that area and new infrastructure. The company we entered with has released a buildup of infrastructure out there. Obviously, it will take some time to get that in. I'm estimating 6 months to a year to get that fully in place where we have higher rates. And not every well is restricted, but Rick, I'd say what? Half the wells, we're seeing restrictions on that, half the wells we're seeing restrictions just due to local infrastructure cannot take the high rates.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Okay. I mean so then firstly, those most recent batch of wells, it is fair to consider that the IP might look more like 30% to 50% higher, you think?

Jeffery Hume

I think you can easily be 25% to 30% higher on those -- on that batch, if we had adequate infrastructure. Having that and pulling them that hard as we could obviously -- if we had the larger infrastructure pull them that hard and whether we'd like to or not, there'd be something else we could argue about also.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Absolutely. And just one more question in the Cana. In the press release, you mentioned in the Lambakis well, I guess was landed in the salacious zone...

Jeffery Hume

That is correct. The upper portion of it is very thick in that area, and we're very excited about that area of the Southeast Cana. We're seeing very thick section of salacious and we're in the upper portion of that salacious member.

Noel Parks - Ladenburg Thalmann & Co. Inc.

That was exactly what I was wondering. I thought I remembered though that maybe some folks earlier in the play had been focusing on the lower because it seemed like it was thicker than the upper. And I remember you were more interested in the upper. But is it just in that far south part of the play that you're seeing a real good thickness of the upper and what sort of thickness are we talking about?

Jack Stark

What we're seeing is -- you're seeing a depositional wedge of salacious material being deposited that thickens as you go into the basin. And down in the Southeast Cana area, you see a nice thick wedge developed coming off of what was the shelf at that time. And in this Southeast Cana area, in the Lambakis area in particular, we're 250-foot thick of Woodford there and it is very salacious. In fact, the upper part is almost 100% salacious, upper half I guess I should say. And the lower half, looks like it's at least 50% salacious. And so we've drilled our first well starting out on the lower part of the upper half, okay, of the upper bench and drilled up through, oh, probably halfway up through that salacious member and completed the well. So we've tested the upper bench here and had very good results. Because this is so thick, we believe there's potential to actually need an additional well down on that lower bench to be able to harvest that rock given how thick the 2 benches are. So overall, we're very excited about the outcome here. It's right in line with what we're hoping to see and to extend this trend another 25 miles to the south, proves up another 15,000 acres that we control right around the Lambakis well there that just really bodes well for our 90,000 acres we have down in the Southeast Cana project.

Operator

Your next question comes from the line of Subash Chandra.

Subash Chandra - Jefferies & Company, Inc.

First, Cana Bakken and the incremental CapEx. If it's in the press release, I missed it. What is the split between Cana Bakken? And then also can you talk about reserve adds through midyear, the split between Cana Bakken?

Jack Stark

Subash, this is Jack. Out of the budget here, we've got about $214 million, the additional dollars allocated towards drilling out of the 250. And of that, about $122 million of that is allocated to the Anadarko Woodford. And that's going to translate to maybe 3 to 4 net wells here this year, maybe 5 in the year incremental. But because we're starting here kind of late in the year, a lot of these costs are really going to be associated with wells that are completed next year. So a lot of these costs, although it'll seem disproportionate just because these wells are being [ph] next year. And that represents 4 rigs that we have coming. One of the operators out there that had 4 rigs they had available, they wanted to take a break on some things they were doing out in the basin. And so we ended up picking up 2 of those rigs and we have 2 more coming here in August. And so we put those to work to a more -- accelerate the development of our play.

Subash Chandra - Jefferies & Company, Inc.

Okay. And then on the reserve adds?

Jack Stark

Run that question by me again, Subash.

Subash Chandra - Jefferies & Company, Inc.

Yes. The reserve additions through year end to midyear, what the split was between the Cana and the Bakken?

Jack Stark

I do not have a breakout in front of me on that. Let me see if we have. Hold on. Here we go. We've got -- Subash, I'm going to get back with you. I don't have a detail on area in front of me. I have an overall summary.

Subash Chandra - Jefferies & Company, Inc.

Okay. It seem like the additions got gas here. So on the surface, it looked like most of the reserve adds were Cana related. I just wanted to confirm that or not. But I'll follow up off-line. How do you feel about North Richland area after these next pair of wells, and do you think we're closer to putting that in the delineated category?

Jeffery Hume

Subash, we've -- on the western end of that north Elm Coulee, the extension of Richland County up between Red River and Elm Coulee, the western half of that acreage block, we're moving that into a de-risked category. We feel like we can consistently make a 430,000 Mboe well or better in that area. So we're ramping our work up in that area. One of our plans over the next 2 years is to bring in additional rigs in that area and start accelerating that. The multistage technology has really unlocked that. Back to the eastern side of that, we've had a mix of wells. We've got couple of wells on the far east end that have done rather well, and a couple of wells that have had higher water cuts. So we feel like there maybe a shear running through there that's affected some of that. We don't know if that's localized or aerial. So at this time, the west -- the eastern side of that north of Elm Coulee, we're putting that as not de-risked yet, although we're very optimistic that will -- a good portion of it will be de-risked.

Subash Chandra - Jefferies & Company, Inc.

Could you put a number on how big the western side is? Is the western half isn't really half of that acreage?

Jack Stark

What I would say is right now, we could probably say in the range about 40,000 acres of really what we consider to be substantially de-risked from the drilling we've done so far.

Subash Chandra - Jefferies & Company, Inc.

Okay. Any update on the -- in the shallow area?

Jeffery Hume

Shallow area? Well, that's where were -- we had the Beaver Creek drilling. And clearly, we have very good indications of hydrocarbons there. And so at this point here with the loss of the rig, we are in the process of getting another rig and we'll be moving back in that area.

Subash Chandra - Jefferies & Company, Inc.

Okay, so that's where it's happening. You didn't lose a frac crew with that?

Jeffery Hume

We were finishing the drilling operation. We've just run the liner, so we still have that well to complete yet.

Subash Chandra - Jefferies & Company, Inc.

Got you. And then finally, I guess the -- when you look at the Lambakis, any of your cost difference between that and your generic Woodford program?

Jeffery Hume

It's slightly deeper. We were probably at 15,000-foot crew vertical depth there, Subash. And that high salacious rock drilled slightly slower. So we're probably in $0.5 million to $1 million higher than the average right in there. Running the economics out on that, we're looking into 60% to 65% internal rate of return on that type of well.

Subash Chandra - Jefferies & Company, Inc.

Is that a sort of $8.5 million well, somewhere there?

Jeffery Hume

Yes. I'd say $8.5 million in that range down there. It varies where we're at on depth. That particular well was at 15,000 feet. As we move into other parts of the Southeast Cana, it will not be that the deep. That's just that particular well.

Subash Chandra - Jefferies & Company, Inc.

Got you. And where does your Cana rig count peak out at?

Harold Hamm

Well, I don't know. Right now, we're at 13 in the Cana and have 2 additional coming in. So we'll be at 15 here in about 30 to 45 days and hold that through the end of the year. And we'll see what our plans are for next year if we accelerate that or maintain or whatever. But we're seeing good results across the play and we're excited about it.

Operator

Your next question comes from the line of Jason Wangler.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

Just curious in the Anadarko Woodford still. Last time we talked, Jeff, you're talking about maybe being able to petition the state for some longer lateral drilling because obviously, I guess the vertical portion is what takes so long. Where do you guys stand on that?

Jeffery Hume

We will have our first hearing. We had it scheduled and there was a protest by another operator that is now been removed. So we'll have that hearing in a couple of weeks I believe, and then we're prepared to drill the well. So I think everything is in place now other than going through having the hearing, getting the order and having authority to drill that. Most of the protest was just people wanting well information, which is part of the drill in Oklahoma Corporation Commission activity. So we feel very confident we'll be on that well within probably inside of 60 days, the location is constructed and it's just a matter of scheduling the rig there once we get the permit. So we don't see any roadblocks at this time of having the hearing and we feel optimistic that we'll be granted a permit to drill and go. So we're anxious to get out and demonstrate that we can drill a longer lateral at lower cost and improve economics for this play and I think it's going to be a game changer for the Anadarko Woodford and for Western Oklahoma development.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

Great, and sorry if I missed it. But are the costs of running just south of $8 million or so around in that area, and you still think you could probably save a couple of million on each well as you go horizontal?

Jeffery Hume

Yes, we think we can save around the -- on a 640 basis, taking it back to 640, we think that we can save $1.5 million to $2 million per well or $3 million to $4 million on a 1,280. But we need to get out and prove that. Our design plans right now is we can drill that well for $12.5 million to $13 million versus 2 wells at $8 million.

Operator

Your next question comes from the line of Hsulin Peng.

Hsulin Peng - Robert W. Baird & Co. Incorporated

This is Hsulin from Robert Baird. Just a clarification question. In Montana, are you keeping your EUR model there at 430 Mboe? If so, what is the potential based on the results you have seen so far, what is the potential for revising that EUR upwards?

Harold Hamm

Well, we think that's on extension area, the Montana, on the increased density or the wells that we're drilling within unit of PUD wells within Elm Coulee itself, we're looking at around 480,000 barrel model and it's looking good. But that area to the north, we've only drilled 4 or 5 wells. Right now as we've seen in other areas as we drill and complete, we always increase reserves. So I feel like as we get the rigs working more on a steady basis in the area north of Elm Coulee, we will increase the reserves for that areas as we continue to tweak how we frac the wells, to how we complete them and how we place the lateral. So right now, we feel very confident that delivering a 430 model and that is at a lower cost over there. We're looking at just a little over $7 million for those wells, shallower and the frac gradient is not as high so your cost of -- for hydraulic horsepower is not as great. And we're also able to use sleeve technology in that area because of the little frac grade, and we have a higher confidence of executing the sleeves versus the perf and plug in getting the sand away. So I think we've got a very good opportunity to improve our economics in that area. So we are excited about that area right now.

Hsulin Peng - Robert W. Baird & Co. Incorporated

Great. And then my second question is more higher level question. Do you think you're outside your goal to triple reserves and production by 2014? And I'm assuming that was predicated on the older EUR model and making them less CapEx. And I was wondering, I mean am I reading it right if I -- just given the higher EUR model and more CapEx, is there a potential for you to exceed that triple production and reserve goal by 2014 based on your current run rate?

Jeffery Hume

Yes, Hsulin, we have done modeling and unconstrained, we could be quite above the 3x. Right now, we're staying with that model because it's -- we're trying to reinvest cash flow and grow it on cash flow as best as we can and keep within our metrics. But we have inventory where we can far exceed that growth rate. And that's what I want to reiterate. We do have an extremely strong inventory of opportunity and depending on cash flow and commodity market and stability of the commodities and the government taxation and how they're treating us, we're going to be able to grow this company at a 3x rates or above for quite a number of years.

Operator

Your next question comes from the line of Marshall Carver.

Marshall Carver - Capital One Southcoast, Inc.

Just a couple of follow-up questions. Have you done much down spacing work recently? I know you talked about that in prior conference calls, but wanted to know was there any downsizing done over the last quarter in the Bakken? And what were your assumptions with those 600,000-barrel wells? I guess some of those were probably -- guess that was just the average of the prior wells, but what are your thoughts on down spacing in the play?

Jeffery Hume

Marshall, we've done several locations where we have 2 1,280s next to one another where we've drilled against the lease line and effectively have 2 wells at a 320-acre space position. But for the most part, we're drilling 1 well and in a few instances, 2 wells in a 1,280. The bulk of our fleets drilling the first well in a 1,280, we're going to maintaining 15 to 18 of the rigs doing that for the next year or 2. We do have a project going right now of testing a 320-acre space unit in our AMI area of galaxy, that's being executed by ConocoPhillips. That's an area where they operate. We're 50-50 partner in that area. We're executing that this summer. We'll have those wells drilled and be producing that. So that's taking down to where on a 1,280 basis we're 1,320 foot between wellbores. And we'll have 4 or 5 wells paired -- developed in that area where we can watch that. The plans are probably to work through or for the most part, work the rigs through to get our acreage HBP and then we'll come back and the fleet will be slowly growing to more ECO-Pad type drilling. We have 4, maybe 5 rigs now capable -- 5 capable of drilling ECO-Pads. We have 3 or 4 at any one time drilling ECO-Pads. And I think we'll be looking at possibly -- the possibility of taking that fleet of ECO-Pad rigs of doing more of this down space testing over the next year. So that's probably where they'll be. So we'll get more on a manufacturing mode, if you will, going across the acreage in late 2012, '13 and beyond where we can convert the bulk of the fleet. And as we grow the fleet, build a more ECO-Pad type development where we get the cost down and price up. But our first step is going on right now with a true 4 to 5 wells, 1,320 foot inter-well spacing. And probably next springtime, we have information on really what's the interference, is there any interference between those. We feel very little. I'll remind you, though, if you look back to Elm Coulee where we have higher permeability, we're effectively drilling that 1,320 foot inter-well spacing and having excellent results. Right now, we're seeing well over 480,000-barrel EURs on average well on our PUDs in Elm Coulee. So we're highly optimistic we'll see very strong results in North Dakota over all of the play.

Harold Hamm

And particularly in this galaxy area, we feel like it's one area that will certainly bode well with 320-acre development. This project that we're doing up there jointly with ConocoPhillips is called Midnight Run. So you'll hear more about Midnight Run as we go forward.

Marshall Carver - Capital One Southcoast, Inc.

Okay, that's helpful. Another question. With the Devon plant downtime, is there any specific impact to you guys at Cana? Should we model that in the third quarter?

Jeffery Hume

No, there's none to us. We're not going to that plant, and the company that we signed up with has multiple plant.

[Audio Gap]

Marshall Carver - Capital One Southcoast, Inc.

Rig counts assuming commodity prices hold up at these levels. How do you think about free cash flow and your balance sheet? I know your rates on equity earlier this year to accelerate drilling, but is there a certain debt level, is it debt to EBITDA that you look at or debt to cap or how do you think about the debt of the balance sheet?

Jack Stark

A couple of points there related to the commodity prices. Obviously we have actively hedged over the last year and a half. We did that in contemplation of the asset we have and our plans to develop it over the next few years. So we're hedged in at plus or minus $90 on crude oil for the next 3 years on the large percentage of our production are forecasted production. So quite a bit of strong stable hedges in place that will give us a floor on the commodity prices. Always moved around a lot. You've seen volatility in our earnings from a mark-to-market perspective. But from a cash flow perspective, that provides us a great deal of stability and flexibility as we go forward. With the quality of the asset we have, the improving results that we're seeing in the asset coupled with those commodity hedges that we have in place and our -- the high margins that we put off on our production that gives us a lot of cash flow that is ever increasing as we're continuing to roll out rigs. So they're going up in line with our increases in rig activity and continue to fund that operation. Related to the metrics, we believe in maintaining a strong, stable balance sheet with strong metrics. That gives us a great deal of flexibility, it puts us in an advantageous position relative to peers and we intend to continue that. So right now if you look at debt to EBITDAX, trailing 12-month of EBITDAX we're less than 1. We are around I think 0.92, 0.93. That's an incredibly strong metric in the E&P sector. So we've got flexibility. If that were to go up a bit, we're still relatively strong. But we've been in that 0.75 to 1.25, 1.5 range for quite some time and that's a very advantageous position. We intend to preserve that.

Adding to that, we obviously announced -- we recently reconfirmed our borrowing base and that is as of June 30, the borrowing base was $2 billion with 0 drawn on that revolver and $261 million of cash on the balance sheet. So again, strong, stable, steady financial metrics.

Operator

Your next question comes from the line of Phil Young [ph].

Unknown Analyst -

Just a quick follow-up question. Regarding the couple of rigs that you got from the other operator, I guess you're going to keep them for about 6 months. Is there any chance that you'd keep them longer than 6 months? That's sort of one part of the question. And the second part is: do those rigs cost -- come at a lower cost than your existing fleet or is it basically the same?

Jeffery Hume

No, it comes -- these rigs are the new modern rigs so they earn slightly higher than our fleet. We took them on at their face value. Right now, our arrangement is to hold them for about a 6-month period and turn them back to the other operator. We could possibly bring other rigs in to take their place and to continue to grow our position out there. But at this time, the plan is on those specific rigs, they will go back to the original operator, that they are contracted under. We just took them for a window. But we will be with our acreage position more than likely growing our rig fleet.

Operator

Your next question comes from the line of Joe Magner.

Joseph Magner - Macquarie Research

You talked about your results on the Bakken wells completed with highway fracs?

Jeffery Hume

Well, we've done 2 of those fracs at this time. And our agreement with Schlumberger is we will not talk about the results of that until we get a group of those finished and have statistical number where it has meaning. What I can tell you is both the fracs we've executed have gone off flawlessly, placed everything in place and everything is looking good. We do have plans to do several more of those and look at the results. And at that time, we'll report that. But today, nothing really to report on individual well.

Joseph Magner - Macquarie Research

Can you speak to the difference in cost versus a normal completion?

Jeffery Hume

I don't know, it's probably 5% higher. You're running more of the fiber gel in there, but I really haven't looked at the bottom line cost myself. So I wouldn't think it'd be much over 4% or 5% difference.

Joseph Magner - Macquarie Research

Okay. Do you have any plans to test the highway fracs in Cana or have you tested that in the past?

Jeffery Hume

No, we don't have any plans for that. Cana is a little different type frac design. We're doing fairly high volume water frac there, higher rates and so I just don't think it's applicable to Cana at this time.

Joseph Magner - Macquarie Research

Okay. And then can you just talk about your results in Cleveland and your exposure out there?

Jeffery Hume

Cleveland, we've had excellent results in the Cleveland. Our exposure, we have acreage there, Jack?

Jack Stark

Yes, we've got about 11 net wells to drill out there on our lease hold. If you assume I think 320-acre spacing in there. So at this point, it's not a big position, I think it's about 4,000 acres. I think that's right. But it is very nice economics there, economics are great. We're looking at 70% rate return type economics out there -- good oil and good gas. And the wells seem to be drilled fairly, fairly nicely for us.

Operator

Your next question comes from the line of Paul [ph].

Unknown Analyst -

Could you guys go in and discuss on the EUR revision any assumptions you had on IP rates, decline rates and well life on that?

Harold Hamm

I think the IP on those were in the first 30 days and the 650-barrel a day range, about 1,000:1 EUR starting out over the life. That EUR will climb at around 2,001 initial instantaneous decline. We've -- the models start out on a monthly rate and not a daily. So that 650, you're probably looking in the mid to high 90% initial decline with a 1.5B factor. And I believe we have 6% or 7% minimum decline 50-year life truncated at that period.

Operator

Thank you. There are no further questions in the queue. I'd now like to hand the call back over to Mr. Hamm.

Harold Hamm

Yes. And to sum up this conference call, first of all, my hat's off to all of our northern district team who used a great deal of ingenuity when conditions became very rough up there. Moving the rigs around across our extensive development areas up there, the Red River in South Dakota, Montana, North Dakota of course and the Bakken. When roads become problematic as we move in South River and kept working. The second thing is longer summer days, dry days are with us up there now. We do have a backlog of completions over couple of dozen wells up there. We're going to quickly turn that production into oil and gas, and we're estimating about 60 days to do that. We have a few main topics here in this call, of course, the EUR is one thing. Geologically, of course, there's deeper Three Forks objectives, seeing shows. Initially, we saw about 50-foot up there and initial core is we want to test the Three Forks. And now we're seeing shows go down 250 feet down. And throughout the zone come and go with different benches, we think that has a great implications for the future of this play. And then also the Southeast Cana confirmation well with Lambakis. The company is increasing our growth rate from 35%, 37% to 36% to 39% and increasing our CapEx gradually as cash flow increases. So I appreciate everybody's attention on the call this morning and thank you very much.

Operator

Thank you. Ladies and gentlemen, that concludes your conference call for today. You may now disconnect. Thank you for joining and have a good day.

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