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Executives

Harold Hamm – Chairman and CEO

Steve Owen – SVP, Land

Rick Muncrief – SVP, Operations

Jack Stark – SVP, Exploration

Jeff Hume – President and COO

Analysts

Subash Chandra – Jefferies & Co

Scott Wilmot – Simmons & Company

Scott Wilmot with Simmons & Company

John Freeman – Raymond James

Gil Yang – BofA Merrill Lynch

Andrew Coleman – Madison Williams

Continental Resources, Inc. (CLR) Q3 2010 Earnings Conference Call November 4, 2010 10:00 AM ET

Operator

Good day ladies and gentlemen and welcome to the Continental Resources third quarter 2010 earnings conference call. This conference 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 will conduct our question and answer period. Additional members of the management are available to answer your questions. And now I will turn the call over to Mr. Hamm.

Harold Hamm

Good morning, everyone. Thank you for joining us on our conference call today. We will abbreviate the presentation part of today’s call since less than 30 days ago we held our 2010 Investor Day, and discussed our operations and growth plans in some great detail in Oklahoma City. If you haven’t seen them, the slides remain available on our website.

We will take plenty of time to respond to your questions after these remarks this morning. In terms of new data for the quarter, we announced another strong increase in production for the third quarter of 2010. Average than normal was 45,000 Boe per day. This was a year-over-year increase of 20% and a consecutive quarter increase of 7% over the second quarter of 2010.

Production growth ramped up in the quarter. In September, we averaged 47,336 Boepd. Though you’ll see that we are well on our way to achieving production growth guidance for 2010 and as we announced October 12, we expect 2011 to be even stronger with production growth of 30%. Crude oil remains 75% of our production and North Dakota continues to drive the increase in overall production. North Dakota Bakken production was just over double in the third quarter compared with the same quarter, same period in 2009.

Along with strong well results overall, we also completed our first ECO-Pad project in North Dakota in the third quarter. The company’s first ECO-Pad project involves a Hegler 1-13H and 2-13H wells and the Arthur 1-12H and 2-12H wells. We targeted a Three Forks zone with Hegler 1-13 and the Arthur 1-12 and they produced 1,195 Boe and 849 Boe respectively.

As we noted in last night’s press release, both these wells were produced on a 22/64 choke with a Hegler flowing at 14,000 psi and the Arthur flowing at 1,150. The other paired wells in this four well project targeted Middle Bakken zone. The Hegler 2-12 produced 1,203 barrels of oil equivalent at 2,200 psi or an 18/64 choke and the Hegler 2-12 produced 1,103 Boe at 2,350 psi on a 18/64 choke. This tiff clearly demonstrates that the Middle Bakken and Three Fork tiff are separate and are communicating and is part of Dunn County.

As we’ve told you in the past, paired wells, the two Hegler wells for instance are drilled with a vertical separation about 50-foot parallel and offset 660 feet horizontally. This is a pattern on which we intent to develop the Bakken field in North Dakota. If you’d like to see a good visual of this, please take a look at the Bakken section of the October 12 slides.

Today we are operating 22 wells – 22 rigs in the Bakken. The Anadarko Woodford production is also continued to accelerate in the third quarter as you would expect. We generated 1,377 Boepd, a 28% increase over the second quarter of 2010. Anadarko production continues to ramp up, we’re now operating six rigs in the play. We’ve planned to add two more by year-end.

Last month we announced a key confirmation well in the Southeast Cana, the Dana number 1-29H which we are 78% in. This is in Grady County, Oklahoma. The Dana flowed at 2.5 million per day and 88 barrels of oil per day in its initial one day test period. This is by far one of the productive well completed in Southeast extension of the play.

As of today the Dana has been online for 76 weeks and its holding steady about 2.3 million cubic feet per day and 65 barrels oil per day at 900 pounds. Southeast Cana has an even higher liquids component in the Cana and the Northwest Cana which is why we’re so excited about it. Because of its 20% higher NGL gas content, Southeast Cana gas yields a 50% higher well ahead price. In addition it has a higher condensate yield at the well.

We expect to continue improving the productivity of wells in this area and are currently drilling another confirmation well in Southeast Cana. Before I leave to Anadarko, we mentioned last month at our Investors Day, that we have most of additional pay horizons in the supply, and that we were drilling a vertical Morrow-Springer test with Rother 2-4 to see how productive this Springer sand might be.

We are very encouraged by the serendipity well. We drilled a 9,200 foot vertical into the Springer and perforated a 13 foot section in the sand. The Rother 2-4 tested at 3 million cubic feet per day into the sales line with some comment side. And now this well in the area produced 3 Bcf per well. With the completed well across only 1.7 million, this was calculated to $0.55 per Mcf cost to add. Continental has an 80% working interest in to Rother 2-4.

In summary, operationally we are proceeding as expected. We are improving drilling efficiencies and production results. We’re preparing ahead all the drilling locations that we’ll need in the Bakken for this upcoming winter.

Now in terms of financial results, we reported $197 million in EBITDAX for the third quarter of 2010, a 53% increase over the same period last year. Our teams are doing excellent job controlling cost and we expect, we can continue to do this effectively as weak gas prices dampen activity in that sector. Finally, we reported $0.23 for net income per diluted share. As we noted in the press release this was after the $0.19 per share negative impact of $14.7 million pre-tax property impairment charge which is actually just leasehold amortization, which will continue to decline as we rapidly convert leasehold into producing units especially in the Bakken.

The $0.19 impact also include a $36.6 million unrealized loss on mark-to-market derivative instruments. We cancellated a $0.19 impact using the impairment charge with a $36.6 million unrealized loss. Our understanding is that’s why most of we calculate what you call our clean earnings per share.

In the Niobrara Shale play, we plan to spud our first long-lateral well, the Newton 1-9H which we own 87% in. In early December 2010 in Northern Weld County, Colorado. This is the first Niobrara well permitted for 1,280-acre spacing in the Colorado portion of the play that we’re aware of. We’re planning to drill a 9,200 foot lateral section this well similar to well design approach in North Dakota Bakken.

We’re permitting additional Niobrara wells in Northern Colorado and Southern Wyoming and based on quality of results with the Newton 1-9H, we expect to spud addition Niobrara wells early in the second quarter next year. Before moving onto Q&A this morning, I’d like to note that we have continued layering all hedges, when we’re seeing good opportunities in the market.

John Hart, our CFO can go into more detail if you would like, but as of today we have hedged 12.1 million barrels of oil in 2011, at an average price of about $85.34. 12.7 million barrels of oil in 2012 at an average price of about $0.87. And 7.1 million barrels of oil in 2013 at an average price of about $89. We’ve taken advantage of recent oil pricing opportunities to layer in account measures in swaps and collars.

As we’ve announced, we expect to generate strong production growth over the next several years, 30% in 2011. And our hedging program builds a solid foundation in this growth program. A complete picture of our hedges will be on the slide presentation that we presented at the BoA [ph] conference late next week. By the way, it’s sure good to be 75% crude oil when we’re working in an $85 price environment.

Today’s strong oil prices benefit our cash position, offsetting a portion of our increased drilling activity. That takes to higher point for the third quarter. So at this point, I’d like to ask our moderator to start the Q&A session participating with me today are Jeff Hume, our President and COO as well as Rick Muncrief and Jack Stark, Senior Vice President of Operation in Exploration respectively. As I noted our CFO John Hart is here. And especially I’d like to introduce to our investors our new Senior Vice President of Land, Steve Owen who has joined the team since the last earnings call. Steve is another veteran in the business we’re very happy to have him on board. Steve, you want to say?

Steve Owen

Thank you Harold and I’m very glad to be part of the Continental team.

Harold Hamm

Thank you Steve. So with that, we’ll start the Q&A this morning.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Subash Chandra with Jefferies & Company. Please proceed.

Subash Chandra – Jefferies & Co

Hi good morning all. On the ECO-Pad, the Three Forks pressures were lower. Should we read anything into that or was that one balanced against choke size, was it very similar what the Bakken did?

Harold Hamm

Subash, what you’re seeing there is in that particular area the Three Forks has lower permeability, and this is going to be flowing at a lower well head pressure than the upper, the bottom hole pressures are pretty much the same on both wells, that’s just showing the difference in the rock fabric and that changes in other parts of the field you’re going to find the Three Forks more productive than the Middle Bakken, but that particular area you’re seeing they’re different. The key point is though as we have them as straight we have separate reservoirs there, we have separate flowing characteristics which is very important.

Subash Chandra – Jefferies & Co

And Richmond County, what’s the status of the Baxter well, and any further into on how EOG completed their well in the county?

Rick Muncrief

Yes Subash, its Rick Muncrief. On the Baxter, we have just completed that well. Just turned it to sales and flowing our load water back at the frac job. Just now starting to cut some oil, so we are encouraged.

Harold Hamm

And the new EOG well, Subash is on the northern side of the M. Cooley [ph] field where results with the old technique, frac techniques, open-hole dual laterals was just not getting the job done as we’re showing the improvement of the multistage frac. It’s exactly what we’ve been talking about on our wells for we’ve come in where we’ve had good completions in the Middle Bakken, in the M. Cooley field and coming between it now with 1,320 foot inter-well spacing. And I think one of the last wells were like 830 barrels a day IP. Very strong results in there and just shows superior completion technology being applied to that field area. And hopefully, we’ll fill that out going north into the Baxter. So it’s a very good news for the area.

Subash Chandra – Jefferies & Co

And again in that area from the un-booked area, I presume from M. Cooley on north, what kind of exposure acreage-wise you have there?

Harold Hamm

I believe its little over 160,000 acres, Jack do you have...

Jack Stark

We’re about 178,000.

Harold Hamm

178,000 acres net area now, Subash.

Subash Chandra – Jefferies & Co

That’s plenty. Okay, terrific. Thank you.

Operator

Your next question comes from the line of Scott Wilmot with Simmons & Company. Please proceed.

Scott Wilmot – Simmons & Company

Good morning guys. At the Analyst Day, you guys mentioned increased rail utilization for takeaway out of the Bakken. Can you talk about your plans in 2011 and utilizing more rail, and kind of just give us a general overview of Bakken takeaway capacity in general and how Continental is positioned?

Harold Hamm

Absolutely, we’ve got multiple opportunities to rail. We’re working with several different companies that are handling that system for us. So what our plan is to get – is to put the oil that we can on the pipeline and as you’re aware of the pipelines are doing many different expansions, expansion programs. Some of those are on existing pipes where they’re using drag reducing agents. And so over the next couple of years until the new pipeline systems are built, we’ll be gaining volumes on the pipeline. So our plan is to maximize utilization of pipelines, where we can and we have very good historic chipper status on those pipes.

So as those expand those we’re going to have a good portion of that. And then the excess, we’ll be moving by rail and so we’re working with several different contractors on that and we’ll be able to handle any excess oil that we cannot get down the pipelines via the rail.

Scott Wilmot with Simmons & Company

Are you able to quantify that extra capacity at this point?

Harold Hamm

The rail capacity or.

Scott Wilmot with Simmons & Company

The capacity that – the excess oil that you’ll have to rail.

Harold Hamm

Well that’s going to very – at this time, I’m moving about 5,000 barrels day on rail and that is pipelines open up, that could shrink back down and as might continue to complete wells and it grows, I’ll probably building the rail even higher. So it’s not a steady state system. It’s a dynamic system. So it’s a hard question to answer. But we’re working and our ahead of the game, and we’ll have adequate rail to move excess oil out.

Scott Wilmot with Simmons & Company

Okay, great. And just when I think about the expansions coming in 2013, I think some of those pipelines have open seasons. Does it look like all those projects that you guys typically list and you’re growing capacities. Does it look like those are going to get done?

Harold Hamm

Well right now they’re in their – they’re in open season all of them are planning to be built at this time. We can’t talk about those in detail because we’re under CAs [ph] we’re looking at all of those. And so we can’t talk about those in detail now, but every one of those are needed and will be built. And I think they’re all on track from conversations with all the pipeline companies everybody is on schedule to meet the proposed timing of their lines. So we feel pretty good about it.

Scott Wilmot with Simmons & Company

Okay, great. Jumping over to the Niobrara, you guys obviously said the first 1280 plant for Colorado. Given the depth of the Niobrara, does that kind of go against convention wisdom of kind of a one-to-one dips to lateral length, and where do you guys seeing that, helps you achieve that longer lateral?

Harold Hamm

Well we’ve seen in areas where we can get out that way that requires us to have some heavier pipe in the vertical to push that out. We’re going to make an attempt on the first well. We feel that we can get that – make that happen. So we’re going to give that a try because we can’t – it’s going to be a significant improvement in the economics. If we can’t, we’ll fall back to the 640-acre lateral length. So we feel very strongly that we can accomplish that but the proof is in the putting. So we’re ready to go.

Scott Wilmot with Simmons & Company

Okay. And what’s the total vertical depth on that well expected to be?

Harold Hamm

It should be probably about 6,500 PVD and while the 92 foot lateral we’re targeting.

Scott Wilmot with Simmons & Company

Okay, great. Thanks guys.

Operator

Your next question comes from the line of John Freeman with Raymond James. Please proceed.

John Freeman – Raymond James

Good morning. On the first ECO-Pad, you’ve got the four wells, I know logistically you all talk about pads, being able to handle 8 potential wells, just in sort of your plans on when you would look at the potentially at least adding like a third Bakken or third Three Forks well that sort of test it down spacing concept?

Harold Hamm

John, we don’t have that on the menu right now, but I think possibly the second half of 2011 we’ll be looking at doing some of that work. It’s going to hold back, it’s a trade-off between acreage HBP and going to full development. We’re going to have more spud bookings, we’ll shake a stick at just the way we’re going and I think orderly development will require us to probably postpone that some. But I think by the end of next 2011, we’ll be giving that an attempt just to see how it works, so we can be modeling that.

John Freeman – Raymond James

Okay, and then with the pad and the fact it ain’t done, there wasn’t any communication between the Three Forks and the Bakken, it looks it’s a separate reservoir. Can you all sort of give an update just ballpark number wise, how much of your acreage in North Dakota you think you’ve sort of de-risked at this point for the Three Forks and the Bakken to be two separate reservoirs?

Harold Hamm

We recently estimated that to be about 75%, and we feel like that is still an adequate number.

John Freeman – Raymond James

Okay and then last question, I’ll turn over somebody else, did the election have any sort of an impact in terms of Oklahoma moving closer to getting approval for drilling on 1280 units?

Harold Hamm

Let’s say well things working here in Oklahoma. We have a very positive environment for drilling exploration in Oklahoma. We are seeing the cross-unit concept beginning to take hold here. And we think that that’s going to go forward obviously as, you know, the shale resource play becomes more prominent, Oklahoma is going to embrace it, we feel.

John Freeman – Raymond James

But at this point there is – now it’s only kind of dark. There is no official date for a vote or anything?

Harold Hamm

There is not.

Operator

(Operator Instructions). Your next question comes from the line of Gil Yang with BofA Merrill Lynch. Please proceed.

Gil Yang – BofA Merrill Lynch

Hi good morning gentlemen. Could you comment on – it looks like your test rate for the 24-hour test periods in the Bakken dropped in the third quarter from the second quarter, you know, 1,000 from 1,250. Can you comment on – is there anything happening there?

Harold Hamm

No, I think just overall, we are not pulling these wells as hard as we were. The gas lines are getting packed and we are just not getting – we are not focusing on IP rates as much, Gil, as some folks are. Some folks are just totally focused on IP rates and we’re trying to get the wells as many molecules we can down the pipeline. So, we are hitting our targets. So wells are looking good and we are feeling very comfortable about it.

Gil Yang – BofA Merrill Lynch

Is that a function of putting a smaller choke size on the well, or is it just not compressing the gas, or how do you…?

Harold Hamm

No, it’s exactly that, it’s just choke the well back, hold it back. So, we’ll – when we start playing the wells up, we claim the laterals out and we pull them back and that’s normally when we get our first day IP, and we quickly get that well back into sales mode. We try to get all molecules down the pipeline that we can. And so in those instances, we got a quite a few wells that they are just late on hook-ups. So, if you can imagine the limited infrastructure up there overrun right now, they are catching up very fast, lots of pipes, lots of screws going in. So, this lag will probably last about another five or six months, should be cured by early spring where we have connections about the time we drill a well, everywhere.

Gil Yang – BofA Merrill Lynch

Okay. Is there any hope that the more moderate early production rate will help in EUR or is that not really what you are looking at?

Harold Hamm

No, well that’s a – we are not doing it for that purpose. That is a question that we kick around and hear, you know, several years ago, we flowed our wells back slow was kind of our policy, bring them back slow to keep sand production down. We changed up our prop and went with the ceramic at the tail end and we don’t have that problem any longer. So we are pulling those back. I have heard a lot of discussion on some of them very hard piece where you just open in the well, wide open, put in a lot of production equivalent out there to get an IP starting a well. You know, I haven’t seen any evidence that it is, but I don’t have detailed evidence on those type of wells, where they have done that. We’ve always had them on a choke with, you know, 1,000 to 2000 pounds flowing pressure when we IP them. So, we try to be consistent on our choke sizes and not just pull them hard. And so, like I say, we are not into an IP business. We are trying to get a nice curve established and go from there. So, but we are very happy with what we are seeing.

Gil Yang – BofA Merrill Lynch

Okay, and when you bring on the ECO-pad, since you have a number of well coming on at the same time, do you have downstream bottlenecks where, you know, if you bring on four wells that are, let’s say the 1,200 each you have to have 5,000 barrels takeaway capacity from that pad, is that creating problems or, you know, do you bring the well in a staggered fashion?

Harold Hamm

No, on the oil side, it’s not a problem at well. We plan ahead on that. We have the trucks for the removal of the oil in the pipeline systems to handle that. It’s mainly on the gas. And where we are building ECO-pads, the gas companies are putting in larger size lines to handle it and making sure they have compression set that can take it – because it is quite a – you bring on a 1,000 barrel day well, you should bring it 4,000-5,000 barrels a day on – hold them back, you are moving 5-6 mcfe of gas. So for – in case you had gathering system that’s pretty good load on compression. So, they are planning that all the pipelines or the midstream companies we are working with are getting that infrastructure in place and handling that, may understand what we are doing. So, we don’t anticipate that to be a problem.

Gil Yang – BofA Merrill Lynch

Is there a significant cost – additional cost to you or the pipeline company for the infrastructure that you end up having to pay for it sometime?

Harold Hamm

Actually, it’s less cost for them, because they are just laying line to one well and is one spot and saving money. You know, most of the cost is the ditch, the pipe size is not that much. The compression is going to be – continued to be used for the area just as my ECO-pad, the first four wells pull down or have another one come on that opens up some compressor space, you know, because these are hyperbolic decline type wells. So, you are going to have – as you bring them on, you are going to have the spike, then you will have depletion after that. So, it’s going to be a walking up scenario as you add wells in areas. So I don’t think it will be a major problem. There will be some spot pinch points, but of course but overall it’s no different than drilling single wells.

Gil Yang – BofA Merrill Lynch

Okay great. And last question. Could you just remind us what the transportation difference is or costs are for shipping by rail versus pipeline?

Harold Hamm

We are seeing probably about $2 difference right now to perhaps $3 on that. It just depends on the market I have on the other end. The rail, the upside to that is I am getting a pure Bakken barrel to a premium market and so I get a bonus for – at that point over Nymex or it’s WTI Cushing Nymex price. So, it depends on what the market is at the time. So, that’s the variation. The rail is a pure tariff. And our agreements with the companies are fee-based. So, the variation is going to be – we are kind of market we can find and they work very hard to find premium markets for that to maximize our income.

Gil Yang – BofA Merrill Lynch

Do you find that the basis – oftentimes it pays – the basis – the benefits for sending – the Cushing benefits you for the higher cost of shipping?

Harold Hamm

Well, we see where that can happen. That’s the vision of the rail companies, they’re in the rail business. They feel like they can compete long term because they can get the superior crude to markets that are in need of it and take it right to where the pipeline, as it goes down the pipeline, obviously gets – oftentimes gets blended with inferior oils, and still meet WTI Cushing specs. So, I think when some of the pipes get it, we will be able to have pure Bakken delivery to markets on pipeline, distant markets on pipeline and on regular basis. But right now, they have an advantage.

Gil Yang – BofA Merrill Lynch

All right, thank you.

Harold Hamm

Thank you.

Operator

Your next question comes from the line of Andrew Coleman with Madison Williams. Please proceed.

Andrew Coleman – Madison Williams

Hey good morning folks.

Harold Hamm

Good morning.

Andrew Coleman – Madison Williams

I was wondering if you guys walk me through I guess how you look at just the cost structure of the Bakken wells. I guess some are fixed and variable split and I guess how much you can break out the processing. I mean did you have any water handling to use in there?

Harold Hamm

No, there is very little water produced in the Bakken for the most part. So that process is pretty limited. We do handle some water in the Norse area. But it’s not a significant portion of the production up there. And we are able to handle up with disposal.

Jeff Hume

And Andrew, we are putting in the Norse area, a pipeline handling system at this time, infrastructure at this time. So, we will handle, it’s got – as you go north you get higher permeable rock, but it has water with it down in the Southern part of the Anticline there’s hardly any water at all. So, it’s just not existing. But to the north, we are – to illuminate trucks is a main thing and to get steadier production through winter and, you know, like a week ago, we a blizzard that shut all trucks down because you could not see. If you believe that or not, but they had a blizzard and high winds that shut trucks down. So, if you don’t have adequate storage capacity on the lease for both oil and water, you shut down. So, we are trying to get pipeline systems where we have significant water production, as Harold said, mainly across the Norse area where we have.

Andrew Coleman – Madison Williams

Okay, you know, I mean, some of the other operators also have turn out numbers on order of kind of $8000-9000 per well per month. I mean, does that seem like – it’s in the ballpark? Because I’ve heard other guys saying it could be in the, you know $7000 range.

Harold Hamm

Andrew, we are not seeing those kinds of numbers. I guess, as you go, you know, further west of the Norse area, you may be looking at our water production and so on a dollar per well month that may not be out of reason for those water producers. We are not seeing that at Norse.

Jeff Hume

You know, we are not seeing that at Norse.

Andrew Coleman – Madison Williams

Okay cool. And then, lastly you know, knowing that the royalty rate there has changed over the last you know I guess couple of years here as the play has gotten hotter, you know, it’s knowing you’ve got a much older legacy land position, I guess, here. Could you, I guess there is no royalty, it was one-sixth, I mean, I guess, what sort of range if you could break it down, you know, in tranches of 50%, it’s kind of one-sixth and the rest getting closer to 20% or I mean is there different split on that?

Harold Hamm

Last time I went through this section, I don’t have the numbers with me. I went through this exercise and had our guys in land pull the average because we thought it would be getting diluted somewhat. And it was around 83% average across our play and what we have is where we have taken some new leases where it might be three-sixteenths. We have also taken some fed releases that are one-eighth, that’s counted there. So, the overall average still around an 83% net. I did that for – exercise for an Analyst Day to run the economics because I wanted to make sure we are delivering the proper math when we gave the type curve economics. And that’s what it’s still at, around 83%. That’s the gain it had been early.

Andrew Coleman – Madison Williams

Okay. Thanks a lot. These are to tweak my single-well model.

Harold Hamm

Yes sir.

Operator

And at this time, we have not further questions. And if there are no further questions, this would conclude today’s conference. And you may now disconnect. Have a great day.

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Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

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