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Executives

Warren Henry – VP, IR

Harold Hamm – CEO

Jeff Hume – COO

John Hart – VP, CFO and Treasurer

Jack Stark – SVP, Exploration

Analysts

John Freeman – Raymond James

Joe Allman – JP Morgan

Leo Mariani – RBC

Eric Hagen – Banc of America

Brian Corales – SMH Capital

Sven Del Pozzo – C.K. Cooper

Continental Resources, Inc. (CLR) Q1 2009 Earnings Call Transcript May 7, 2009 10:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the first quarter 2009 Continental Resources Incorporated earnings conference call. My name is Tanisha and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the call over to your host for today's call, Mr. Warren Henry, Vice President of Investor Relations. Please proceed, sir.

Warren Henry

Thank you, Tanisha. Good morning, everyone, and welcome to our earnings conference call. On today's call, we may discuss projections, assumption 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 our first quarter achievements. Jeff Hume, Chief Operating Officer, will provide additional detail on operating developments. Finally, John Hart, Chief Financial Officer, will discuss our financial results. After John’s comments, we will be ready for Q&A. Jack Stark, our Senior VP of Exploration, will also be available for Q&A.

With that, I'd like to turn the call over to Harold.

Harold Hamm

Good morning, everyone. Thanks for joining us on the call this morning. Given that so many of our peer companies are reporting this week, we've decided to keep our first quarter conference call as concise and direct as possible and then move directly to your questions about the quarter and current operations. We are pleased to report record production for the first quarter.

Our production was 36,808 Boepd, 22% higher than the first quarter of 2008 and 2% higher than the fourth quarter last year. This was achieved despite a severe reduction in drilling activity and despite the ongoing conversion of producing wells to injectors in the Red River units, which obviously cost us some production short-term. Certainly, 2% of our first quarter 2009 production was crude oil and 28% was natural gas.

Once again, the strongest growth was generated in the North Dakota Bakken and the Arkoma Woodford. We reported a net loss of $27 million and an EBITDAX of $58 million for the first quarter. Not surprisingly, both are below the results for the same period last year due to the dramatic pullback in commodity prices. Excluding the $35 million pretax charge to impairments, our pro forma net loss would have been $4.6 million or $0.03 per share, not including overall inventory gain.

As noted in our earnings release this morning, Continental realized price per BOE was $29.98 in the first quarter of 2009, a decrease of 63% from the first quarter last year. We saw almost equal percentage declines in prices for crude oil and natural gas. Crude oil prices improved significantly in March. Our average realized price in March was $43.63, which includes an average differential of $4.43. We saw further improvement in April.

Finally, we reported $93 million in total oil and gas sales for the first quarter, a decline from last year’s first quarter reflecting a drop in oil and gas prices. Sales did not fully reflect our record production since we put 216,000 barrels of crude oil into storage during the first quarter of 2009. Given the low commodity prices, we have intently focused on balance sheet management.

Capital expenditures were $153 million for the first quarter. Our full year budget remains $275 million. So obviously we are aggressively laying down rigs and taking those steps to enable the company to end the year with CapEx generally in line with cash flow. We have reduced our operating rig count to four rigs, down from 32 in October and 13 as of January 1st.

We are operating two rigs in the North Dakota Bakken and one each in the Arkoma and the Anadarko Woodford. Only one rig has a contract term beyond three months from today, and we plan to keep laying down rigs. We are also monitoring closely our participation in non-operated well, especially natural gas wells, and opting out in cases where rates of return are lower where we don’t want to allocate CapEx right now.

In summary, our fiscal discipline remains in place. We are preparing to adjust if crude oil prices continue to strengthen, which we think they will. I would like to remind you that even with deep cuts in drilling activity, we expect to grow production 4% to 8% this year. Investments that we have made in the last 18 months, especially in Red River units, will continue to drive our growth through mid-2010.

Aside from balance sheet management or other key discipline in this environment is operating efficiency. In the first quarter of 2009, we reduced production expense to $7.24 per BOE compared with $7.83 in the immediately previous quarter and $8.33 in the first quarter of 2008.

On an absolute basis, production expense declined to $22.4 million in the first quarter of 2009, a reduction from the $26.4 million in the fourth quarter of 2008 and from $23.1 million in the first quarter of 2008. We expect additional opportunities to reduce drilling and completion costs when we start signing new drilling rig contracts. Day rates are down significantly as a result of almost 50% US land rigs being laid down since October.

In terms of the broader business environment, we have a positive outlook on crude oil demand and crude oil prices. We expect to see transportation and agricultural fuel demand increase over the next few months and continue into 2010. This increased demand should absorb the current oversupply of crude oil very quickly and support higher crude prices.

It appears that the market has been anticipating these and other factors as prices have trended higher, closing over $56 yesterday. This bodes well for CLR, given that we are heavily weighted in crude oil. At about $60 per barrel, the rate of return on the projects become much more attractive and would increase discretionary cash flow for investment or for debt reduction.

Our near-term outlook for natural gas is now strong however. Our long-term outlook for natural gas is positive, especially given the new administration's focus on cleaner burning energy for electricity production. We think that the abundant US supplies of natural gas are a logical green energy source as we seek to import less foreign oil and reduce carbon emissions.

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

Jeff Hume

Thank you, Harold. I'd like to briefly review our first quarter operations and give you a sense of our outlook for the rest of the year. We are continuing to implement the secondary water flood program in the Red River units. First quarter production was 14,162 barrels of oil equivalent per day, but within the quarter production actually trended lower from January into February and March. We expected this as we continued to take producing wells offline and convert them to injection wells in the units. We expect production in the units to increase in the second half of 2009 and peak in mid 2010.

Now let’s turn to the Bakken. We have a lot going on in North Dakota despite the cutback in drilling rigs since the beginning of the year. North Dakota production increased 4,807 net barrels of oil equivalent per day in the first quarter of 2009, three times higher than production in the first quarter of 2008 and a 9% increase over the fourth quarter of 2008.

During the first quarter of 2009, we completed 26 gross, 7.3 net wells in North Dakota. Six of the gross wells and eight-tens net are awaiting frac and production facilities. The rest averaged 489 barrels of oil equivalent per day in their initial seven-day production test. These first quarter completions, seven Three Forks/Sanish wells averaged more than 500 barrels of oil equivalent per day over seven-day production periods, with the most prolific being the Parrish 1-31H, which produced 795 barrels of oil equivalent per day.

Of the seven wells we noted in our press release, I’d like to point out that the Landblom 1-35H, the Lawrence 1-24H, and the Myrtle 1-7H wells were drilled in the Williams and Divide Counties, our northern most acreage, which we call the North Prospect. These wells produced at 648, 645 and 603 barrels of oil equivalent per day respectively over seven-day test periods. We are very pleased with these strong results. We had one company-operated Middle Bakken completion in the first quarter, the Rossow 1-10H in Divide County, which produced 329 barrels of oil equivalent per day in its initial seven-day test period.

As noted in this morning’s press release, we have participated in five more well completions in McKenzie County, North Dakota since the beginning of the second quarter. Two of these were company-operated wells that targeted the Three Forks/Sanish zone. The Merton 1-3H, which produced 912 barrels of oil equivalent per day, and the George 1-18H, which produced 896 barrels of oil equivalent per day in their initial seven-day test periods..

The other three wells were drilled by ConocoPhillips in our AMI acreage targeting the Middle Bakken zone. These were some ConocoPhillips’ strongest wells to date in this region. The Iron Horse 31-2H, which produced 1,085 barrels of oil equivalent per day; the Sunline 31-12H, which produced 927 barrels of oil equivalent per day; and the Waterton 34-32H, which produced 886 barrels of oil equivalent per day. Please note that these are all seven-day averages, the same as we measure our own initial production.

So overall we are very pleased with our recent drilling success in North Dakota and we plan to capitalize on improving results as prices continue to recover. We are currently drilling a Middle Bakken companion well to confirm our belief that the Three Forks/Sanish and Middle Bakken are separate producing zones. We are drilling the Mathistad 2-35H with a lateral well bore approximately 60 feet above and 200 feet to the side of the existing Mathistad 1-35. We completed the Mathistad 1-35H in McKenzie County in mid-2008 in a Three Forks/Sanish zone. And it produced 1,260 barrels of oil equivalent per day during its initial seven-day test period.

The company will monitor pressures and performance of both wells to determine whether the two zones act as separate producing reservoirs in that part of the play. Based on our reservoir stimulation fracture modeling, we believe the two zones are not in communication over most of the play. If substantiated by drilling experience, this will significantly increase the reserve potential of our North Dakota Bakken acreage.

One additional positive development recently was the completion of gas gathering and processing system in our – to service our North Prospect. We are currently processing approximately 350 gross barrels in NGO liquids, and 2.1 million cubic feet of residue gas with additional capacity expansion expected in the near future.

In the Montana Bakken, the company continued to implement its 320-acre infield and field-extension program in the first quarter of 2009. Notable completions included the Mondalin 3-10H, where we own 71% working interest, and the Stoney Butte Farms 3-17H, with 83% working interest. These wells produced at 625 and 474 barrels of oil equivalent per day respectively in their initial seven-day test periods.

Although we have currently suspended drilling in Richland County, we will revisit this decision if crude oil prices continue to trend positively. We have 55 gross locations targeted for drilling in the 320-acre infield program. Finally, we noted in this morning’s press release that our pilot carbon dioxide injection project in Richland County is continuing. Utilizing the huff-and-puff technique, carbon dioxide was injected, and allowed to diffuse into the reservoir. The carbon dioxide and associated fluids are currently flowing back and being analyzed for performance and economics.

Given the reduction in drilling activity in the Bakken, we have wrapped up our efforts and have been very successful in extending leases in the Bakken at reasonable rates. Our overall acreage position in the Bakken play was 612,000 net acres at March 31, 2009. Approximately 19% of this acreage is held by production. As a result of our lease renewal efforts, only about 7% of our Bakken undeveloped acreage is currently subject to lease expiration in 2009. This exposure is less than 15% in 2010. We are working diligently to further reduce their exposure.

Moving to the Arkoma Woodford, our first quarter 2009 production was 4,799 barrels of oil equivalent per day, an increase of 153% over the first quarter of last year and 47% higher than the fourth quarter of 2008. We participated in 27 gross wells and 4.4 net in the first quarter, and we currently have one rig active in the play with another drilling in the Anadarko Woodford, west of the Arkoma.

With that, I will turn it over to John Hart, our CFO.

John Hart

Thank you, Jeff. I’d like to provide a little more color on a few income statement and balance sheet items before turning the call over for Q&A. As you saw this morning, our first quarter 2009 net income included pretax property impairments of $35.4 million which compares with a pretax $4.5 million in the first quarter of 2008. Apart from the $35.4 million charge, Continental's net loss was $4.6 million, or $0.03 per share, for the first quarter of 2009. Clearly, our earnings would have been higher had we not chosen to store 216,000 barrels of crude oil in the first quarter.

The $35.4 million pretax impairment charge included $9.4 million for impairment of non-producing properties, which is self-explanatory given the continued low level of commodity prices. In the press release, we broke down the $26 million, the remaining $26 million for impairment of developed oil and gas properties to make sure that investors understood that these do not involve our highest value plays. $14.1 million related to uneconomic drilling results in two single-well fields completed in the first quarter of 2009, which are located in Western Oklahoma and the Texas panhandle. The remainder of this impairment charge primarily is related to uneconomic wells in Texas and in non-Bakken Montana properties.

As we noted in this morning’s press release, long-term debt was $544 million at March 31, 2009. As of April 30th and through today, our borrowings had increased to $577 million, leaving us with availability under our current revolver of $95.5 million. We routinely worked closely with existing and prospective banks and believe that we can continue to increase the commitments under our credit facility should we desire additional liquidity. Fairly soon we expect our banks will begin our semi-annual borrowing base re-determination. We do not expect that this will lessen our borrowing capacity.

As we noted in February, our expectation was that debt would grow the second quarter as we have reduced our drilling activity. We also indicated that we expect it to reduce our debt level in the second half of 2009. That remains our intention. Near-term we are focused on fiscal discipline while maintaining a strong balance sheet. We want to be in a position to reaccelerate our drilling operations quickly and aggressively when the rebound begins.

With that, I would like to turn the call over to the operator for Q&A.

Question-and-Answer Session

Operator

Thank you. (Operator instructions) And your first question comes from the line of John Freeman from Raymond James. Please proceed.

John Freeman – Raymond James

Good morning, guys.

Harold Hamm

Good morning, John.

John Freeman – Raymond James

First question I had, on the two exploratory wells that were uneconomic during the quarter, were those Anadarko Woodford and Atoka, or is that somewhere else?

Harold Hamm

They were the Anadarko Atoka wells, and those include the Shrooder [ph] and the Jones Trust, which were noted in the 10-K. And so these were wells that the completion information is provided in the 10-K, but essentially the wells completed at rates that we considered uneconomic in today’s prices and therefore had to be impaired.

John Freeman – Raymond James

Okay. And any idea at this point on how much of the acreage in the Anadarko Woodford do you think is probably impaired with this, or is it just too early to tell?

Harold Hamm

You just said Anadarko Woodford and this was Anadarko Atoka. We’ve got about 20,000 net acres in the Atoka play itself out there. And at this point, we would like to see better results, but we know from the results that we are seeing from other operators out there that commercial production is being established. So the impairment of that acreage is something we are debating.

John Freeman – Raymond James

Okay. Sorry, I apologize. It is not the Anadarko Woodford, it’s the Atoka.

Harold Hamm

Yes.

John Freeman – Raymond James

Okay, thanks. And then on the companion well, any sense of like how long do you think you are going to have to let that well produce till you have a better idea or a clear view if it is a separate reservoir?

Jeff Hume

Yes, John, what we are doing on that, we will be landing the 7-H this weekend or early next week. The number one well will be pulling to tubing out and sealing off of the bottom of the well bore and putting bottom hole pressure gauges in that. So we will be watching the pressure as we drill the lateral to see if there is any open fractures into the well bore as we drill it. Following that, we will – after we finish drilling that well, it will be a roughly 10 to 12-day period before we frac the well. We will leave those pressure bombs in there for the frac stage.

We will do a multi-stage frac, exactly the same as we did on the number one well. And then we will put the number two well on production and watch it for a couple of months, maybe three months with pressure gauges, so the number one will be isolated and watching pressure as we do that. And that will give us a sense of the vertical permeability as well as any major fracture openings between the two zones. So I would say after – about four months from now, we ought to have some early indication of where we're at on the production and more than likely to get established the client curves back. We’re probably looking at six to nine to have very conclusive. But I think some early data will come out of the frac interference and the production interference at first three months of production.

John Freeman – Raymond James

Okay. I appreciate that detail. Moving on, on the Bakken, just trying to get a better sense of where kind of current completed well costs sit just with the day rate declines you are seeing as well as just the efficiency gains on drilling these wells quicker.

Jeff Hume

Yes. We are getting some great efficiency gains, John. We are down to two rigs. And on those two rigs, the last eight wells – nothing pulled out. The last eight wells, we've completed those in 28.4 days average per well with a total depth average of just under 20,000 feet each. So we’ve really worked on efficiencies with our team. The drilling team has done a great job. The completion team is getting the fracture cost down. Our most recent well is flowing. Currently in cost, we’re underneath $5 million on that. So if we can maintain this performance level, we can get our cost down in that sub $5 million range.

Right now, we are AFE-ing the wells at around 5.3 to 5.6 million depending on where we are at the field. We have not begun to renew drilling contracts. So we feel like when we renew the rig contracts and start accelerating our program again, we will see much reduced prices there, as well as the casing. We are still working on casing inventory that was – we are committed to from last year. So we will see additional reductions from that. So overall, we’ve stated in the past we can see 30%, potentially up as high as 40% reduction. We are probably seeing 18% to 20% at this time.

John Freeman – Raymond James

Okay. And then a last question, I’ll turn it over to somebody else. I know the Trenton Black River has kind of been pushed to the back burner with all the reduced activity. But if Jack could just kind of give me an update on that play in terms of if the original plan to acquire the 3D seismic was done and if he has any sense of kind of how many locations you are currently looking at there when eventually commodity prices rebound and we start drilling again there.

Jack Stark

John, we did complete a three square mile 3D shoot out there, Ohio [ph] shoot. And we have really identified several locations on that 3D shoot. We are in the process of acquiring another 2.5 to 3 square miles on another project to the west of there. So, although we didn’t really do any drilling here this first quarter, we have acquired the seismic. And as far as total locations that we have out there, I really don’t have a total number because we are essentially combining what we have here from these three – this new 3D shoot that we’ve got. But we’re probably looking well over a dozen.

John Freeman – Raymond James

Great. Thanks a lot, guys.

Operator

And your next question comes from the line of Joe Allman from JP Morgan. Please proceed.

Joe Allman – JP Morgan

Thank you. Good morning, everybody.

Harold Hamm

Good morning, Joe.

Jeff Hume

Good morning, Joe. How are you?

Joe Allman – JP Morgan

Good, thank you. In terms of – on the Montana Bakken, in your press release you indicated that you reentered an old well bore and you did a stimulation, which I guess was a re-stimulation, because I imagine you stimulated the first well. Could you talk about that, like how much did that cost? I think you gave in the release it’s 150 barrels of incremental production. And what’s the upside there? I mean, can you do that across the whole field?

Harold Hamm

Joe, the details on that well, that was a single lateral, open hole completion that we tried early. So we reentered that well, cleaned it out, cleaned all the sand out of it, reamed it out, ran a liner with multi-stage packers, and I believe we did a ten-stage frac in that well. It may have been a 14, I don’t have that details in front of me. But we brought that on. That cost us probably somewhere in the $1.5 million to $2.0 million range with the multi-stage frac and the liner and the cleanout.

What we have in the field is 57 wells, where we have dual lateral completions, our early ones, where we have two open-hole laterals, which we could fairly easily go in and clean out one of those laterals and run the liners in those and do multi-stage frac on at least half the lateral. So there is potential we could do that for approximately half that cost in the $1 million, $1.25 million range for a gain of – we are seeing a stabilized gain of over 150 barrels a day on this first well. So you could model it to picking up 75 to 100 barrels a day gross on $1 million to $1.25 million investment.

Joe Allman – JP Morgan

Okay, got you. Okay, that’s helpful. And then in terms of the rigs, I know you have four rigs running; one Arkoma, one Anadarko, two North Dakota Bakken. The two North Dakota Bakken, are they targeting Three Forks? It appears that the Three Forks is just working better than the Middle Bakken. Could you just comment on that?

Jack Stark

Joe, this is Jack. We have continued our focus on Three Forks. I agree with you. We’ve seen good results in the Three Forks and continue to do it, and you’re right.

Joe Allman – JP Morgan

The plan going forward would just be to really focus on the Three Forks, knocking many of those out as you can and resume the Middle Bakken?

Jack Stark

Yes.

Jeff Hume

That is correct, except the Mathistad 2 we are drilling in the Middle Bakken right now. Other than that, we will be drilling predominantly Three Fork/Sanish wells, Joe.

Joe Allman – JP Morgan

Okay, got you. Okay, that’s helpful. And then in the Anadarko Woodford shale, could you just talk about what you are seeing there recently? And I think you might have an asset package there for sale. Could you talk about that too?

Jeff Hume

Well, we had a package out. We were testing the market to see if we could sell part of that down to help firm up the balance sheet and spread some of our risk, which we've done quite a few times in the past. We did that with the North Dakota Bakken. We thought that was the prudent thing to do. The testing so far, we’ve got two wells drilled. One of those is had a packer failure at the middle of the fracs. That's been repaired and we are scheduled to complete the fracturing on that next week or the week after. The first well, we did extensive testing on that. I flow tested the heel section by itself for a period of time. We've just now commingled that this week and we will be releasing information on that later in the quarter.

Joe Allman – JP Morgan

Okay, very helpful. Okay, thank you.

Jeff Hume

Right. And then we have one rig running now in the Caina [ph] field drilling a well in the Anadarko Woodford, which would be our third test.

Joe Allman – JP Morgan

Okay, helpful. Thank you.

Operator

And your next question comes from the line of Leo Mariani from RBC. Please proceed.

Leo Mariani – RBC

Hi, good morning here, guys?

Harold Hamm

Good morning, Leo.

John Hart

Good morning, Leo.

Leo Mariani – RBC

Hi. Just a question concerning the traditional Arkoma Woodford play, just curious if you guys had an simul-frac well that you recently brought on line. Any update on that?

Harold Hamm

We have not – that we’ve recently brought on line, I don’t believe – you know, we’re drilling a set of those to the simul-frac as we speak.

Jeff Hume

Right. At the very end of December, we completed the Pasquali simul-fracs and then we had the Wilson simul-fracs as well that we announced previously.

Leo Mariani – RBC

Okay. I know you folks also have a position in the Haynesville Shale. A couple of questions related to that. Have you been buying any more acreage lately? And what’s your plan to drill a well out there?

Harold Hamm

Yes, we do have some prime acreage there in the Haynesville and we're pursuing that other acreage and we like our position. We just don’t have enough of it we feel.

Leo Mariani – RBC

Okay. Is there a well on schedule for 2009 now?

Harold Hamm

We do not have one scheduled at this point.

Leo Mariani – RBC

Okay. In the Bakken, can you guys comment on what you are seeing in terms of recent oil price differentials out there?

Jeff Hume

Well, we saw the differentials, as we said earlier, come down to around four and change in March. They came back out a little bit in April. But we are seeing things firming up there. Part of that is some of the line space, the takeaway capacity out of Guernsey has freed. We actually had the Platt pipeline out of proration for a period of time, which helped prices there. I feel with the White Cliffs line filling and taking product out of the Denver area that will – they have around 20,000 barrels a day out of the DJ Basin committed to that. We will start seeing those differentials at Guernsey start moving back to where their normal range would have been. And hopefully we will see that continuing to firm up as we expand pipeline capacity in the basin. You know, the Enbridge line is supposed to increase over 50,000 barrels a day by the first quarter of 2010. So we feel like we will be getting differentials back down the historic levels of – down in that $2 to $4 range out in the future as those pipes come in to play. But we’d just have to wait and see where that goes.

Leo Mariani – RBC

Okay. Thanks a lot, guys.

Jeff Hume

Thanks, Leo.

Operator

And your next question comes from the line of Eric Hagen from Banc of America. Please proceed.

Eric Hagen – Banc of America

Hi, good morning.

Harold Hamm

Good morning.

Eric Hagen – Banc of America

A question on the Anadarko Woodford, a follow-up on Joe’s question, how much acreage do you have there and how much is in the Caina Field or at least the area, which Devon has talked about?

Harold Hamm

We’ve got 117,000 acreage in the play. And we are about – I think about 80% of that is undeveloped, 20% is HBP. And as a percentage within the Caina area itself, boy, I tell you, I’m going to it’s – you're in that area of about 15%, 20% and in and around. And it really is hard to say. I mean, I don’t know how – it's defining what the Caina Field is. I mean, it covers several townships in there, as we see it. So we’ve got a good position in and around a long trend.

Eric Hagen – Banc of America

Okay, great. Thanks, that’s helpful. And then on the – in terms of ramping up, if you do decide the ramp-up, any sort of approximation of how many rigs you might add, say, in the second half of the year? Would those go right into the North Dakota Bakken, might you add one into Montana? Just any potential color on that?

Harold Hamm

Eric, our focus, first of all, would be in the North Dakota side, the North Dakota Bakken. And I doubt if in the second half we put rigs bag in the Montana side this year at least. Obviously we are back in the range that we’ve put rigs back to work. So I see that ramp up – just according to where oil prices go, we thought that perhaps we would see $60 this month and it looks like we’re pretty close. So I think that we’re going to be focusing – are focused on being on undeveloped acreage up there and we've got some awfully good stuff to drill.

Eric Hagen – Banc of America

Okay, great. And then last one I have is just on railing volumes out of the Bakken. EOG has talked about that. Any thoughts on that? Is that a potential for you or not, given your location?

Harold Hamm

Actually we’ve been up there a lot longer than most people. And we’ve got historic – we're a historic shipper on most of those pipes. And that does us a good service. So we are – right now we are not railing any barrels, we don’t have a need to. So I don’t see us picking that back up as new pipeline capacity comes on, and I think we’d be in good shape without railing.

Eric Hagen – Banc of America

Okay, thanks. If I could just ask you one quick follow-up on that one, is there a big cost difference between the pipeline and railing? Can you give me an idea of what that might be?

Harold Hamm

There is cost differential between those two. And you’re probably looking at $5 to $6 differences, would be my estimation.

Eric Hagen – Banc of America

Okay. Thank you very much.

Harold Hamm

Yes.

Operator

And your next question comes from the line of Brian Corales from SMH Capital. Please proceed.

Brian Corales – SMH Capital

Hi, guys. I just want to kind of – in the traditional Woodford and the Arkoma, what are you all seeing on price there now?

Jeff Hume

On the gas price?

Brian Corales – SMH Capital

No, on the cost side.

Jeff Hume

On the cost side? We’ve been doing our wells where we’ve been drilling in there, been running around $4.6 million to $4.8 million completed.

Brian Corales – SMH Capital

And how many stage fracs are those?

Jeff Hume

Nine stage.

Brian Corales – SMH Capital

Okay. And just hopping up back to the Bakken, the 216,000 barrels that’s in storage, was that primarily priced? Was the pipeline full? And is that forward sold? And how should we look at that going forward?

Harold Hamm

Actually there are two factors that we were looking at back there. We first started to storing its oil, and one was the high differential that we felt like would improve drastically, and it has. So that was the first consideration. The other one was price. Basically we were able to move that forward and actually had August delivery on sales. So we moved it from a low price environment up to a much better price environment. And so it’s just where our storage facilities up there paid off.

Brian Corales – SMH Capital

Right. And just back to the previous question in terms of accelerating as prices come back, where would be the first place you would accelerate, assuming oil comes back first? I mean, would it be – would you add rigs in the Bakken in early ’10 if we were in, call it, $60 NYMEX world?

Harold Hamm

We are set to go back and work there in the Bakken. We’ve got several locations already built and plans to go forward. So we’ve got a team that’s projected where we need to move forward. So we are all set to go do that.

Brian Corales – SMH Capital

Okay. All right, thanks guys.

Harold Hamm

Thanks, Brian.

Operator

And your next question comes from the line of Sven Del Pozzo from C.K. Cooper. Please proceed.

Sven Del Pozzo – C.K. Cooper

Yes, that’s Sven, first name. Hi, how are you doing?

Harold Hamm

Good morning, Sven.

Sven Del Pozzo – C.K. Cooper

Good morning. I’d like to know what the Mathistad 2 can tell you that you haven’t already learned from the list of Three Forks/Sanish wells that you’ve got in your press release.

Harold Hamm

There’s a couple things. We’ve had strong belief all along that these two were separate reservoirs. And I think that everybody after we first drill those first wells, jumped over and started drilling Three Forks within the area where it's predominant with the thick layer of lower Bakken over it. So everybody made that change pretty quickly after we drilled Bice and the first Mathistad. We just feel like these are two separate reservoirs. We need confirmation of it. And it had put us on to more of the dual development where we can perhaps do a super pad and drill four wells off of one pad, two going one direction with the Three Forks/Sanish and Middle Bakken, and two going the other way. So it just let’s us utilize a lot of the synergies putting all the facilities in one place and gathered facilities and whatever.

Sven Del Pozzo – C.K. Cooper

And just to confirm, those Three Forks/Sanish wells that you listed in the press release, they were only completed in the Three Forks/Sanish? There are no other zones?

Harold Hamm

That is correct. They are single laterals in the Three Forks/Sanish.

Sven Del Pozzo – C.K. Cooper

Okay. And also you mentioned early on in the call CapEx of about $150 million. But then just looking at the cash flow statement, it looks like the cash outflow is in – from investing activity is about $206 million. Would you able to reconcile the two numbers a little bit for me?

John Hart

Yes. The $206 million is the cash that was expended during the quarter. That obviously includes charges that were incurred in the fourth quarter, but weren’t tied into the first quarter, so that the cash flow number is high because you are paying off that run-off of invoices associated with work that was done in the first quarter – pardon me, the first quarter, by the way.

Sven Del Pozzo – C.K. Cooper

Okay. And then could I get an update on White Cliffs completion, like what percentage of the pipe is already finished?

Jeff Hume

It’s finished. It’s in the final stage at this time. And the last word I had was it would fill in May, become operational – fully operational in June. So I haven’t seen any other information to change that. So I believe that’s where it’s at.

Sven Del Pozzo – C.K. Cooper

Okay. And I think – yes, that’s about it. Well, thank you very much, gentlemen.

Harold Hamm

Thank you.

Jeff Hume

Thank you.

Operator

And we have a follow-up question from Joe Allman from JP Morgan. Please proceed.

Joe Allman – JP Morgan

Thanks again. In terms of the infrastructure in the Bakken, just to clarify, so you're not railing anything. So does that mean you are piping everything or are you trucking some oil?

Harold Hamm

No, we are piping everything that we’re producing up there.

Joe Allman – JP Morgan

Okay. I appreciate that. And then in terms of the differentials, going forward, do you see any reason why the differentials might widen similar to what they did late last year and previously? Or do you think – I mean, given what we know now, it’s pretty much clear sailing. And could you also comment about the seasonality of the differentials?

Harold Hamm

Joe, I think that the seasonality of differentials is going to be a lot less this year. All these rigs going down, it’s lowered production up there within those two states, Montana and North Dakota, drastically. It’s off some 50,000 to 60,000 barrels when you look at the two states together. So there would be some seasonality to it, probably within the peak of the winter months, January, February, perhaps late December. But I would expect it to be a lot less than normal.

Joe Allman – JP Morgan

Okay, that’s helpful. And then, Harold, I know you were pushing to reduce the allowables for gas production in the State of Oklahoma. Could you update on that?

Harold Hamm

Well, the normal hearing process turns up every six months in Oklahoma to assess demand. And obviously demand is down for natural gas in the US due to the recession. That's been estimated at about 5 to 6 Bcf across country. So Oklahoma will adjust their allowables accordingly. And a normal process comes up in July. So there would be a hearing at that commission in July and that’s when that’s done. I would expect them to pull that back considerably.

Joe Allman – JP Morgan

Okay. So (inaudible) now 60% or 65%?

Harold Hamm

Yes. I don’t know – I can’t say where they will put the number right now. It’s 65% of the calculated absolute open flow and then they pull back as far as about 25% if they want to.

Joe Allman – JP Morgan

Okay. I thought they would have a hearing in May. I thought they are going to adjust the schedule some because of the circumstances.

Harold Hamm

Well, actually the commission wanted to call a special hearing, but by the time they went through the process, giving notice and doing all that, you’re in mid-May, you’re almost to the normal hearing date anyway. So it’s just best to wait another 45 days and see what demand is at that time.

Joe Allman – JP Morgan

Okay. All right, very helpful. Thank you.

Harold Hamm

Yes.

Operator

And we have a follow-up question from the line of Sven Del Pozzo from C.K. Cooper. Please proceed.

Sven Del Pozzo – C.K. Cooper

Yes. In the beginning of the call you said the Three Forks/Sanish wells were drilled in the northern part of your acreage. When I’m looking at your map on the – and see your acreage distributed along the Nesson Anticline, where can I picture some of these wells that you drilled have the good results? How far north?

Jack Stark

Well, I was going to say, when you say how far north, right up to the northern edge of our acreage, really in – and kind of the easiest way to view this is that all along, they are all the way from what we consider our Rocket project, all the way up to the Norse project. We are seeing very comparable outcomes. And our focus is really in the drilling in the Three Forks/Sanish, as we said previously. Other wells, we are participating with other parties. They oftentimes are targeting Middle Bakken, but a few of those are also Three Forks/Sanish wells as well. So if you are looking for an absolute – I'd say, probably about – from about 144 north and up, if you’re looking at a map, in particular township 144 north and up to a northern extent of our acreage.

Jeff Hume

Sven, we are seeing good results from Dunn County, McKenzie County, Williams, clear up into Divide. So all through there up and down that Nesson Anticline we are seeing strong results.

Sven Del Pozzo – C.K. Cooper

And is the distance of the Three Forks from the Middle Bakken there – I've seen the press release, you mentioned about 60 feet of separation from the Mathistad number two. What kind of separation is there between the Middle Bakken and the Three Forks in some of those wells that you had in the press release?

Jack Stark

It ranges anywhere from 50 feet up to about 100. On the south end, down way south, down in Dunn County, it’s more in the range of 50 feet. And when you get up into Divide County, you are at 100.

Sven Del Pozzo – C.K. Cooper

Okay. All right. Well, that’s encouraging. Thank you very much.

Harold Hamm

Thanks, Sven.

Operator

(Operator instructions)

Warren Henry

Is that the end of the questions, Tanisha?

Operator

Yes, sir. They are the end of the questions.

Harold Hamm

Okay. Thank you, everybody, for joining us. I know it’s been a busy week for everybody. We appreciate your attention this morning. Thank you very much.

Operator

Thank you for your participation in today’s conference. This concludes your presentation. You may now disconnect and have a wonderful day.

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Source: Continental Resources, Inc. Q1 2009 Earnings Call Transcript
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