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Continental Resources, Inc. (NYSE:CLR)

Q2 2009 Earnings Call Transcript

August 6, 2009 10:00 am ET

Executives

Harold Hamm – CEO

John Hart – SVP, CFO and Treasurer

Jack Stark – SVP, Exploration

Gene Carlson – SVP, Resource Development

Tom Luttrell – SVP, Land

Rick Muncrief – SVP, Operations

Analysts

John Freeman - Raymond James

Subash Chandra - Jefferies & Co.

Steve Berman - Pritchard Capital Partners

Chris Pikul – Morgan Keegan & Company, Inc

Sven Del Pozzo – C.K. Cooper & Company

Leo Mariani – RBC Capital Markets

Ronnie Eisenmann – JPMorgan

Mitch Wordsmith [ph]

Operator

Good day, ladies and gentlemen, and welcome to the second quarter 2009 Continental Resources earnings conference call. This conference call is being recorded. Today’s call will include projections, assumptions and guidance that are considered forward-looking statements. Actual results will likely differ from those contained in our forward-looking statements. Please refer to the company's filings with the Securities and Exchange Commission for additional information concerning these statements and risks.

Chairman and CEO, Harold Hamm, will begin this morning's call with an overview of our second quarter achievements. He will be provided by Chief Financial Officer, John Hart; and Jack Stark, Senior Vice President of Exploration, who will provide additional details on financial and operational results. Finally, in addition to these, several additional officers will be available to answer your question in the Q&A period. Gene Carlson, Senior Vice President of Resource Development; Tom Luttrell, Senior Vice President of Land; and Rick Muncrief, Senior Vice President of Operations. Chief Operating Officer Jeff Hume is traveling today and will not be participating on today’s call.

At this point I would like to turn the call over to Mr Hamm. Please proceed sir.

Harold Hamm

Good morning. Thank you for joining us today for the second quarter conference call.

Over the past 43 years that I have been building Continental Resources, nothing has diminished my own thrill and excitement as when we have such a large find as the addition of the Three Forks/Sanish to the Bakken shale play. This is the same thrill I think that I have had with the (inaudible) play in Oklahoma, our Cedar Hills build in North Dakota and Elm Coulee in Montana.

Continental has sponsored a project, research project with Mathistad 2 well, in cooperation and with the support of a North Dakota Industrial Commission, the oil and gas research program to determine as best we can whether Three Forks/Sanish is indeed independent producible horizon. And in our call this morning, we are going to discuss the results that we have obtained from that test. The data from this research project will be available to the general public later this year. We will file a report probably by November.

We will also unveil Continental’s plans to harvest the Three Forks/Sanish in the Middle Bakken across the acres that we own using to a large extent ECO-Pads. We have obtained regulatory approval from the North Dakota industrial commission to use ECO-Pads and can literally drill these units we spaced up there fence to fence. So, this will utilize about 15% additional reservoir space from what we have been using or at least 11% -- 1100 feet more within the reservoir, and this is going to be at a cost savings we believe of 10% or more.

Let me say right here that a regulatory body known as the NDIC [ph] has been very responsive to amend rules to accommodate efficient horizontal drilling not only in this play, but in the Cedar Hills play and other horizontal plays across the state up there. So it is a great state to work here for producers and it is an engineering-based group and they do an awfully good job.

Lastly, we have announced the expansion of our CapEx budget this morning, about 42%. We think this allows to accelerate the development phase for assets in the Bakken, where we have the potential to rapidly and substantially grow Continental's reserves over the next several years.

Since Continental drilled its first Three Forks/Sanish well in the (inaudible) back in 2008, there have been about 100 wells drilled now and completed up there in Three Forks/Sanish. Continental has drilled about half of these number I think is 47. The Mathistad 2 well now is a validation that the Three Forks/Sanish Middle Bakken are indeed separate producing formations. We are now joining the cores that seems like in this second quarter conference call here at Bakken operators who share this general belief the Mathistad 2-35 strong initial production of 995 barrels of oil equivalent per day indicates that we did tap new undrained reservoir rock in the Middle Bakken that was not affected with first well Mathistad 1-35 which has completed over 100,000 barrels was completed in Three Forks/Sanish in mid 2008. We tapped new reservoir rock in the Middle Bakken. Let me explain our approach in drilling and completing this Mathistad 2-35 test and what we did learn in this process.

To fully appreciate the result of this test, I think you need to step back and understand the extreme conditions under which it was performed. It was a research project and what we have here are two horizontal well bores basically drilled right on top of each other and not bearing over about 150 feet and actually crossed in the middle. So it is drilled on the same north-south orientation and separated vertically by 50 foot, which is a lower Bakken shale with one horizontal well drilled in the Middle Bakken zone and the other in the Three Forks/Sanish zones below it.

Both horizontals were independently fracture stimulated, the first being back in mid 2008 as I said and therefore we effectively stimulated [ph] these two well bores 9500 foot long, one well stacked on the other with combined 24 stages of 39,000 barrels of frac pud and 1.9 million pounds of sand for both wells. We fraced these two horizontals in such a confined area with these volumes that I think this is kind of unprecedented in the Bakken play and maybe anywhere else.

I understand though as a practical matter, we would never do this out in the normal practice with all said and done, and somewhat we won't be right on top of one another probably. Our idea was though that if they were spaced with only (inaudible) and vertical separation, they didn't not communicate clearly [ph] between them when the second well is fraced and there is no way you will have a communication issue between up and lower zones when you transition into full field development.

So, while fracing the Mathistad 2-35H, we did observe some pressure spikes in the lower Three Forks/Sanish well bore (inaudible) communication we feel was insignificant if any. Both wells have produced completely independent of the other and we get into a lot more detail about that in this discussion. But the huge difference in productivity, the 995 barrels a day going from Mathistad 2-35 versus the 187 barrels oil equivalent per day that was previously pumping from the lower well bore (inaudible) from new undrained reservoir rock in the Middle Bakken zone, with the new Mathistad 2-35 well.

And likewise, the number one well seems to be the same type of producer now that was before we shut it down initially. If we ultimately find that these minimal amounts of oil are seeping through the frac (inaudible) and Three Forks, we do not think it will affect the development of the two reservoirs. Without question, the (inaudible) that will take a separate horizontal well bore in each of these two reservoirs to harvest their reserves efficiently.

So, what does this mean to Continental as we transition into a development mode in the Bakken to efficiently harvest both of these reservoirs? This test was very important to us and I believe we did (inaudible) is stacking two laterals and established not even with unrealistically tight spacing the Middle Bakken and Three Forks/Sanish reservoirs are separate and need be developed individually. Consequently in terms of testing we have seen what we effectively need to see. So given the extensive number of wells that we and others have completed across playing both zones, as I said earlier, Continental is now transitioning into the developmental mode with a staggered drilling pattern that we will use to harvest the two reservoirs.

The most effective way to drain these two tanks so to speak is to drill north south oriented Middle Bakken well and then step over to about 660 feet east or west and drill Three Forks/Sanish well in the same orientation and then step over another 660 feet and drill the next Middle Bakken well working your way out across play. We think this development plan dovetails very well with the ECO-pad concept that the NDIC approved this last week. Continental has developed an innovative new approach for drilling multiple wells around the same old drilling pad specifically the two Middle Bakken and two Three Forks/Sanish wells per ECO-pad.

The key advantages we think are very apparent. We drilled four wells from one ECO-pad minimizing the environmental impact. One ECO-pad will have about 70% less space as the surface footprint area than four conventional drilling pads. Instead of four pads, basically we use about 5 acres each up there for (inaudible) drilling platform and therefore we will be drilling four wells sequentially from a single 6-acre ECO-pad.

Another aspect of this one ECO-pad will require construction one access road versus four and each separate well still being dispersed over 1280 section [ph] will be in one ECO-pad and of course that will minimize road construction, pipeline hookups and everything down the road. Secondly, we expect this to reduce drilling completion cost per well about 10% and we can elaborate on this in the Q&A session. Here, we have got Rick Muncrief with us. But primarily we are talking about less rig time (inaudible) less frac pud handling and a lot of other operating efficiencies and then of course we will have the same operating efficiencies as we produce these wells going forward.

Yet the most important economic benefit I think stems from the fact that the NDIC granted ECO-pads an exemption from setback requirements on section [ph] property lines. We'll be drilling fence to fence from 1280 acreage spacing unit to the next, instead of leaving about 1100 feet or more untouched rock between these two 1200 acre space units. So we will be utilizing all the reservoirs within our space unit.

So let me explain that, I think if you picture in your mind two 1280 acres spaced drilling units or you added vertically end to end north to south right now we are drilling the horizontal well bore for the well in the first unit 9500 foot long typically north to south stopping short of the unit southern property line and shifting to the next adjacent 1280 unit to the south, will skip another gap from the northern property line and drill the next well with its 9500 foot horizontal section.

So looking from above, you have the first horizontal, a 1100 foot gap and then the second horizontal well bore, a 1100 feet of unfraced, untouched reservoir left in the ground between the two wells and does not fit anyone, and later on some times you have to go back as we did in the Cedar Hills deal and actually extend those laterals or whatever if you do secondary or tertiary. With the NDIC’s blessing, we can now set an ECO-pad right in the middle of this gap and drill first well north and second well south from the same pad. We will harvest a reservoir with an additional 1100 feet of horizontal well bore and even more when you consider we do not have setbacks on the (inaudible) either.

Then we will step over 660 feet to the west and do it again with the additional well pairs oriented north and south. Resulting increased production and completion efficiency benefits everybody from the State of North Dakota and this is the great oil producing state up there and I think this is going to be very meaningful to them to the metal owners and to producers such as Continental. We are excited about the ECO-pad concept and we look forward to reporting to you as we begin to implement the concept late in this year or in early 2010.

Now we have got a lot more to discuss here this morning in terms of the second quarter achievement. So I think at this point I would like to turn the call over to John Hart, he is going to discuss the financial results. John?

John Hart

Thanks Harold. We were very pleased with our operating and financial results for the second quarter of 2009. Increased commodity prices helped drive improved cash flow, which enabled us to reduce borrowings on our revolving credit facility and accelerate drilling activity as we entered the second half of the year.

Compared with a loss in the first quarter, we reported net income of $13.5 million or $0.08 per diluted share during the second quarter. This included a pretax property impairment charge of $23.3 million and mark-to-market gains on natural gas fixed price and basis swaps of $890,000. Apart from these non-cash items, our net income was $27.1 million or $0.16 per diluted share for the second quarter of 2009. Our average daily production was 37,347 Boe per day for the second quarter, which represented an increase of 18% over 31,623 Boe per day in the second quarter of 2008. Now obviously, our production gains were more than offset by a decline of 58% in the average price per Boe in the second quarter of 2009 versus the same period in the previous year.

Total oil and natural gas sales were $146.4 million for the second quarter, which compared to $297.6 million for the second quarter of 2008. Our production exceeded sales during the quarter due to the company placing an additional 35,000 barrels of crude oil in storage. As of June 30, 2009, we had 669,000 barrels of crude oil in storage. This is roughly split 50/50 between line fill and tank storage. As noted in our earnings release, we began using the increased cash flows generated from higher crude oil prices to reduce borrowings on the credit facility to $572 million as of August 6 and we plan to end 2009 in the mid 500s.

Now, I would like to direct your attention to one other aspect of our balance sheet management, which is the fact that we improved our liquidity position in the first half of 2009. At March 31, we had $544 million in long-term debt and additionally we had negative working capital of $53 million, which together totalled $597 million of effective debt. At the end of the quarter, we also had a borrowing availability of $129 million. Contrast that to June 30 where we had $592 million of long-term debt but our working capital position had improved significantly to where we had a positive working capital of $23 million, which netted against the debt yields $569 million of effective debt. Additionally, at the end of the second quarter, commitments on our revolving credit facility had been increased to $750 million and we had availability of $158 million. That has further improved. As of August 06, our availability has further increased to $178 million based on lower outstanding debt. So as you can see, our liquidity position improved dramatically during the quarter.

With that I will now turn it over to Jack Stark.

Jack Stark

Thank you John and good morning everyone. As Harold has pointed out, the second quarter was quite eventful for Continental and in the interest of time I will focus my discussion on the North Dakota Bakken and the budget increase we announced earlier today. The rest we will be glad to handle in the Q&A.

During the quarter our Bakken production grew to an average of 12,391 barrels of oil equivalent per day, up 47% over the second quarter of ‘08 and 13% over the first quarter ’09. Essentially all of this growth is coming from the North Dakota Bakken where production has tripled since the second quarter of ’08 and rose an impressive 31% over the first quarter of ’09.

During the quarter our Bakken drilling was located exclusively in North Dakota where we completed or participated in the completion of 11 gross, 4.9 net Three Forks/Sanish wells and 17 gross, 3.2 net Middle Bakken wells. Combined these wells posted the highest quarterly average initial rates we have experienced today in North Dakota with a seven-day average of 737 barrels of oil equivalent per day. Of significance is the fact that these wells were evenly distributed across their Nessen [ph] acreage.

Likewise the completion rates were quite consistent with 65% of our operated wells completed since the beginning of the second quarter posting seven-day averaging of initial rates of over 800 barrels equivalent per day. Three of these wells completed rates in excess of 1000 barrels a day. You can find the details for these wells in this morning’s press release. I might highlights the Kukla 1-21H located in Dunn County, which posted the best seven-day initial rate at 1,429 barrels equivalent per day. The Kukla is a Three Forks/Sanish completion and represents the highest initial rate we have seen from our operated Three Forks/Sanish wells to date.

As you may know and I think many of you do, we have been the leader in testing the Three Forks/Sanish in North Dakota and today we have drilled and completed 46 gross, 22.4 net Three Forks/Sanish wells representing almost 50% of the horizontal completions in the Basin today. We are quite pleased with our higher initial rates from our second quarter wells since higher IPs have historically translated to higher URs. So we will be monitoring production closely and will adjust accordingly.

To complement these good results our drilling and completion costs have continued to come down significantly. Average drilling days from spud to rig release have dropped by almost 40% from 45 days in 2008 to 28 days in the first half of 2009. Our Bakken team has done a great job improving our drilling efficiencies and in fact they just reached TD on a 21,000 foot Three Forks/Sanish well in a remarkable 16 days with one motor and one bit to drill the entire lateral section and this is not a one-time event. This is actually our third operated well to reach TD in 16 days. So from the combination of fewer days drilling and lower service cost, we see our completed well cost migrating to around $5 million in the second half of the year which is more than 20% lower than our typical AFE in 2008. During the first half of 2009, our completed well cost averaged approximately $5.4 million with our most recent wells coming in at around $5 billion each.

Now I cannot leave the Bakken without touching on the implications of the Mathistad 2 on the unrisked reserve potential to our North Dakota acreage. We currently own 605,000 net acres in the Bakken play of which 439,000 is located in North Dakota. As we have shown in our corporate presentations, we have over 500 potential net wells on our North Dakota acreage with estimated unrisked reserver potential of 160 million barrels of oil equivalent. This assumes only one producing zone, 640 acres spacing, 400,000 barrels equivalent of gross or 325,000 barrels equivalent net reserves per well.

We believe at least 50% of our North Dakota Bakken acreage has potentially the harvest reserves from both the Middle Bakken and Three Forks, which adds another 80 million barrels to Continental’s unrisked reserve potential. All totalled, the net unrisked reserve potential for Continental North Dakota acreage now stands at 240 million barrels of oil equivalent which is about one and a half times our proved reserves at year end 2008 and really this number could actually double should 320 acres spacing be warranted as it is in Montana in the Bakken there in Elm Coulee field in Richland County,

Now before turning to the revised budget, I would like to quickly mention that production from our Red River unit was 14,092 barrels of oil equivalent per day in the second quarter of 2009, essentially flat with the first quarter representing 38% of our total corporate production. We continue to convert producing wells to injectors and expect that production in midyear to get up around 17,000 barrels equivalent per day.

Now let us talk about the revised budget. As stated in our May conference call, we plan to increase our pace of drilling once oil prices returned to the $0.60 per barrel or more range. Prices are there and this morning we announced a 42% increase to our CapEx budget for the year going from $275 million to $390 million. Essentially all of the $115 million increase is allocated to drilling in the North Dakota Bakken play and we have wasted no time adding rigs in North Dakota and currently have three operator rigs in the play and plan to add two more during the fourth quarter. This will have us exiting 2009 with five operator rigs in play instead of one as we have originally planned. We also planned to keep one rig operating in the Arkoma Woodford through year-end. Since these rigs are being deployed in the third quarters and fourth quarters, we have not changed our 2009 production guidance but these rigs will provide momentum to accelerate production growth going into 2010.

Looking forward, we expect prices to remain above the $60 per barrel level but the reality is we cannot be sure. So we will remain flexible and will do so by contracting rigs on a well-to-well basis. This allows us to rig quickly and do any significant change just as we have in the past. And with that I might also note that we have only one rig under long-term contract.

With that that concludes our presentation and we suspect our comments today have stimulated a lot of thoughts and our management team is here and ready to address your questions. So we will now open it up for questions.

Question-and-Answer Session

Operator

(Operator instructions) Our first question will be from the line of John Freeman from Raymond James. Please proceed sir.

John Freeman - Raymond James

Good morning guys, congratulations on the Three Forks test.

Harold Hamm

Thanks John.

John Freeman - Raymond James

The first question I have since you do have now basically in the industry a 100 wells in the Three Forks, as I mentioned half are yours, I am trying to get a sense of what – after you have done this extensive reservoir test, what do you think that your reserve engineer is going to need at the end of this year to start giving you all Three Forks locations and offsets like they would in the Bakken?

Jack Stark

I think we had the basic material that we need to go forward but Gene Carlson is here with us and Gene you want to comment on what you all might need down there?

Gene Carlson

Sure. We do not see any difficulty in looking at where we have proven the productivity of both zones but the problem is we need to go back now and confirm that both zones are productive in given areas and confirm that these same conditions that we have measured with this test exist in those areas. If we can do that I think we can book both zones but we need to have both zones being confirmed as productive in several more areas.

John Freeman - Raymond James

And what do you think the time frame of that is?

Gene Carlson

Our drilling plans for next year will be to do that exact thing over more areas including some areas that we already have both zones producing in.

John Freeman - Raymond James

So it could potentially be more of probably a 2010 event than your ’09 reserve report?

Gene Carlson

I would say so, yes.

John Freeman - Raymond James

And then I am trying to get a sense with the pad drilling how that would potentially improve I guess the likelihood of down spacing and what plans you all would have to begin some 320 acre down space wells?

Harold Hamm

Let me pick up right there and add that we have several areas here that we believe this has proven already and obviously our Galaxy [ph] and Rocket areas has had extensive drilling in both zones through there as well as Norse. Basically up and down the Nessen there. We see much of this play – we have established both zones in it at this time. So we are ready to go without a doubt and save all these areas. We talked about when we would be going forward these ECO-pads and we have spaced a number of them – right now we are busy in there getting permits where we need it from Federal acreage to accommodate this very same thing. So we are ready to go to flat business acreage.

John Freeman - Raymond James

Okay and then last question and then I will turn it over to somebody else, given that the pads now are going to let you drill a longer lateral, you know, 10,500 plus and given the success that some of your competitors have had of stepping out 20 and 24-stage fracs, have you any plans to increase the number of fracs status on the current 14 you are employing?

Harold Hamm

Well we have been looking at the increased number of fracs and trying to validate the success of those, we are going to continue doing that but obviously you add more reservoir length lateral, you are going to need to step up the frac number. So we plan to do that.

John Freeman - Raymond James

But nothing definitive in terms of when we might first see a well that would have more frac stages?

Harold Hamm

The most we have done is 14 so we would step up another two stages or so, we are going to be looking at 16 just on the same density that we now hire within laterals. We are going to continue looking at the other operators and gauging their success. We very well may step up the problem.

John Freeman - Raymond James

Great, thanks guys, great quarter.

Harold Hamm

Thanks

Operator

Thank you. Our next question will be from the line of Subash Chandra from Jefferies & Co. Please proceed.

Subash Chandra - Jefferies & Co

Hi, good morning, congrats as well. I am trying to understand sort of how you would drill these wells out from this point forward, so I guess if you have any ECO-Pad, are you going to still do say one Bakken or Three Forks well going out over two sections or you are going to do that 660-foot displacement next to each other and then vertically. So I mean are we talking about drilling one well and completing it or drilling up to four wells or something or more and coming back and completing all of them?

Harold Hamm

We see these ECO-Pads basically as initially holding four wells and basically they are two wells going opposite directions with each other and both zones and we would be placing those about 660 feet apart instead of being right on top of one another and that write-down looks to be the configuration.

Subash Chandra - Jefferies & Co

I guess with sort of 5,000 feet to work with, you still leave an awful lot of land untouched?

Harold Hamm

It does and we see development for sure (inaudible) to these ECO-Pads within each double unit at best we may save six to eight wells on each one. With the equipment that is out there and technology, our group here is technical for sure and we try to employ the best of everything that is out there with the walking rigs actually move the 20s wells with a pipe and a derrick this just does not save a tremendous amount of time and we wanted to get into this development mode quickly, sooner than later, so we have moved into it now. As you can see, it is a huge savings and additional reservoir to take advantage of.

Subash Chandra - Jefferies & Co

So it still turns out to be sort of 1280 spacing except it is now 1280 in the Bakken and then 1280 in the Three Forks.

Harold Hamm

Actually we would probably drill down to about 640 basis here and we would add two ECO-Pads per pair.

Subash Chandra - Jefferies & Co

Two per pair, got you. What are you thinking now on how much you need to drill in order for lease retention?

Harold Hamm

Excuse me, I did not understand your question, how much we need to drill before what?

Subash Chandra - Jefferies & Co

How for lease retention the drilling program just for lease retention?

Jack Stark

Subash, this is Jack, we can get to these leases and get them drilled. It is a plan that would take probably three, four years to get to the bulk of this acreage still HPP, we have got a lot of drilling out in front of us, which is a great deal. We have got term loan leases and we are just going to continue to develop this lease and we are continuing to expand the productive limits of this field. So I am glad to say we have got quite a few years of drilling ahead of us.

Subash Chandra - Jefferies & Co

So as I look at sort of the improvement in the seven-day IPs Q2 to Q1, do you attribute that to more frac stages or bigger mix of Three Forks wells, what specifically happened?

Harold Hamm

We think it is a Three Forks/Sanish, I think we will look back on this later on and it is the second zone here that we realized potential of in this play that I think when it is all said and done it is not going to be the bananas but a banana split.

Subash Chandra - Jefferies & Co

And one final one for me, Anadarko Woodford, any update there?

Jack Stark

We are continuing to drill ahead Subash on the six wells that we are drilling in the Foster unit and then we will have a six well Simon frac – I am sorry, did you say Anadarko?

Subash Chandra - Jefferies & Co

Yes, I am sorry, Anadarko.

Jack Stark

Right now we are – next week we will be fracing the Young well, it is 55% working interest, it was drilled close up into the Canfield area, where you are seeing (inaudible) and Devon drilling, so we had it going and should frac it next week.

Subash Chandra - Jefferies & Co

So you have how many wells fraced at this point?

Jack Stark

We have actually got the McCalla well, that is the well that we drilled a little bit further south on our acreage block. We had some mechanical issues, we have talked about that before on that well so we really do not have a valid test down there. So we are drilling the Young, we will get it fraced and then our plans would be to move down there and get another good sanitary test down on that acreage block down in the south.

Subash Chandra - Jefferies & Co

Great, thank you.

Jack Stark

Al right.

Harold Hamm

Thank you.

Operator

Thank you. Our next question will be from the line of Steve Berman. Please proceed sir.

Steve Berman - Pritchard Capital Partners

Yes, good morning, just a quick follow-up to Subash’s last question, what county is that Young well in?

Jack Stark

It is going to be Canadian County.

Gene Carlson

It is Canadian County.

Steve Berman - Pritchard Capital Partners

Can we talk about what properties were impacted by the impairment shortages?

John Hart

The impairment is, you know, of the $23 million about $13 million of it is undeveloped leasehold across the United States. We amortize leasehold over the term of its lease. So with our large position, you do have a level of amortization and impairment of that leasehold over the course of the lease. The other is a one-well test and so in Oklahoma the McCalla that Jack referred to, we had a variety of mechanical difficulties on that. The well is producing but due to the mechanical difficulties we had, it is not producing at the level we expected. So we took a $10 million charge on that.

Steve Berman - Pritchard Capital Partners

Okay and just your overall thoughts on natural gas which is $0.20 as we speak have not changed, you are still negative on that for the foreseeable future.

John Hart

We can talk about natural gas, we see that as a completely different subject from crude oil. We have always been bullish on crude oil and we see crude oil with a diminished gray line [ph] as propagating tartar and the future’s economic recession than it has ever been. With natural gas we do have a lot of gas on hand and we have seen cutback on a lot of rigs that we have seen with the extended recession here, economic downturn, that demand has not come back as quickly and so it kind of pushed things out yet. So we are still thinking that we are not going to see much in 2010 and 2011 it could be a much different story.

Steve Berman - Pritchard Capital Partners

Would you look to add any more natural gas hedges in the near future?

Harold Hamm

Absolutely.

Steve Berman - Pritchard Capital Partners

All right, thank you gentlemen. I will let someone else go.

Operator

Thank you. Our next question will be from the line of Chris Pikul from Morgan Keegan. Please proceed.

Chris Pikul – Morgan Keegan & Company, Inc

Thank you guys. I wanted to have another follow-up on the -- I guess Subash’s question about the better productivity we are seeing in the second quarter. You kind of alluded to the Three Forks. Are there any other factors in the way you are completing the wells or the quality acreage or just simply a higher component of Three Forks?

Jack Stark

Yes. I think it’s a higher component of Three Forks. If you look at last year, we were on average at 10 stages per well. We are at 14 stages per well now, but we feel it’s strongly influenced by the larger population of Three Forks completions.

Chris Pikul – Morgan Keegan & Company, Inc

Do you feel like that’s a sustainable trend or at least results you can replicate going forward?

Jack Stark

Well, we hope so. We are drilling in some good areas. We are very bullish about the areas we are in. It’s hard to say absolutely, yes, but we are optimistic.

Chris Pikul – Morgan Keegan & Company, Inc

But there is nothing that stands out in the second quarter that represents an anomaly in your eyes?

Jack Stark

We don’t think so.

Chris Pikul – Morgan Keegan & Company, Inc

And then, as far as the Three Forks/Sanish, that’s a great test there, what is the primary factor influencing the decision or the conclusion that these are two reservoirs? Is it just the thickness of the Lower Bakken primarily, are there other things we should be working about and how did you come across -- how did you come up with your roughly 50% risk factor?

Harold Hamm

Well, I did not understand the 50% risk factor, but the -- obviously it’s production from the two wells. I mean that is really the overwhelming evidence. As I said, we did see frac (inaudible) one well to the other, but we have just not seen any clear communication that we can determine at this point.

Chris Pikul – Morgan Keegan & Company, Inc

Is that because of the thickness of the Lower Bakken, do you need 50 feet, do you need 100 feet, is that an important factor?

Jack Stark

Well, I think that it is a factor, but we see this shale as a pretty good barrier between that. The 50% number that I think you were referring to later is probably our Nessen acreage out there. 50% of our acreage does have Bakken under it and we feel that the 50% number that we have given will have effective Three Forks/Sanish under that.

Chris Pikul – Morgan Keegan & Company, Inc

But is that just a function of the presence of the Three Forks or is that also -- whoever tweaking that number?

Jack Stark

Well, what that is, that is the area where we seeing 40, 50-foot of separation between the Middle Bakken and Three Forks/Sanish, and also we have Three Forks/Sanish and Middle Bakken producers in all of these areas. So its really the whole Nessen acreage block have test in both zones and now with this test showing that the zones are acting as separate reservoirs, we perceive all of this has potential for both zones being productive. So that’s where that number comes from and it is a specific number based on the acreage we have in all those projects.

Chris Pikul – Morgan Keegan & Company, Inc

Great. And then lastly, just to confirm, so do you believe 50 feet is sort of a minimal kind of number?

Jack Stark

Well, we have shown that out and we really can’t say. I mean that was just a number that was our best estimate and it still remains an estimate right now. I mean, I don’t really have any basis to say that, we’ve run models that show that we can’t frac across the Lower Bakken Shale even when it is 25 foot big. So it could actually acreage -- larger percentage of our acreage could actually have Three Forks perpetual than what I am saying here. But I guess we’ve been a little bit conservative. I mean we are happy with this, but we don’t need to overstate on it. But we feel comfortable that in those areas, where we’ve had wells drilled, I mean I can take you all the way from our most northerly project to our Southern one on the Nessen incline and we have both Middle Bakken and Three Forks producers of comparable quality on both ends. And so to me, its just you are starting to fill in the blanks here and --

Chris Pikul – Morgan Keegan & Company, Inc

Thanks for the color. That’s good news guys. Thanks a lot.

Jack Stark

Yes. Thanks a lot.

Operator

Thank you. Our next question will be from the line of Sven Del Pozzo from C.K. Cooper. Please proceed.

Sven Del Pozzo - C.K. Cooper & Company

Yes. Good morning.

Jack Stark

Good morning.

Sven Del Pozzo - C.K. Cooper & Company

I would like to know, I am trying to think about what your drilling schedule will be in terms of completion. How many wells might you be able to drill and complete, say in a steady state, where would you like to be in an environment of $70 oil assuming that you passed all the environmental hurdles and you start to drill quite efficiently from pads because you’ve got a tremendously rich asset base and I am just wondering how long it will take you to develop your huge inventory?

John Hart

We’ve looked not a whole lot further than a five-year plan and developing that, we’ve got a five-rig case now. And I would like to say with oil prices being supportive, we think we can add in 2011 maybe a rig per month, and going up to about 20 rigs and hover in that level. It might be something like $600 million budget out there in the Bakken alone and I think that would be supportive to get the job done for us (inaudible) is repaying all the acreage that we have and built a play effectively. So it is a very long-term development project for the company.

Sven Del Pozzo - C.K. Cooper & Company

Okay. And adding one rig per month going up to 20, you are also taking into consideration the pad drilling and the efficiencies that would be generated with pad drilling.

John Hart

That’s correct.

Sven Del Pozzo - C.K. Cooper & Company

Okay. And have you compared, I am just wondering, if you continue to drill without pads and then moving to the pad drilling, is there any way to quantify what the main difference will be in terms of how many wells you will be able to drill and complete in a given time period?

John Hart

Obviously, the pad drilling, we think is just the way to go and I think it is going to add to the number of wells we can drill over time by maybe 15%, 20%.

Sven Del Pozzo - C.K. Cooper & Company

Okay. Then I was wondering about the other (inaudible) also talked about the Haynesville which was a similar kind of idea trying to see whether the Middle Bakken and Three Forks/Sanish were indeed separate, I don’t know whether you followed that well in Western Montreal County and compared it with your own results and do you have any few or any -- did you find that the results on that interesting and what might it mean do you think overall for the basin?

Harold Hamm

We have not, I heard that Jim [ph] thought that these two rig orders were separate, that didn’t surprise me. We’ve not followed that particular well though.

Sven Del Pozzo - C.K. Cooper & Company

Okay. And do you think that the environmental hurdles that you started to mention at the beginning of the call, what are the major hurdles that you guys need to overcome in order to make sure that you can get to that to reach that 20 rig program out in time and honestly how difficult do you think it will in order to satisfy the conditions required by any environmental legislation?

Harold Hamm

Actually, these ECO-Pads are very environmentally friendly. So it takes less than ever before as far as economic -- environmental hurdles. It’s very friendly to the environment, you are disturbing a lot less up here and most of our acreage is on fee acreage. Some areas we do have Federal and we just had to arrange the citing of these particular wells and so it’s kind of changed what we were doing in order to accommodate it. And so its more internal staff time and whatever than it is outside the time. So that’s what we work with. There is no environmental hurdles that I am worried up here at all.

Sven Del Pozzo - C.K. Cooper & Company

Okay. And then I would not want to lose track of the Montana Bakken. I am wondering you had a decent acreage position there in terms of undeveloped acreage there and I am wondering whether that stuff might be perspective as well for Three Forks/Sanish and if not, I mean how does it compare with your North Dakota acreage?

Harold Hamm

Actually, Elm Coulee was an awfully good field and it is holding that part of production very well. We are still over 6,000 barrels a day at the end of the quarter. So we are very glad to have that production. And we don't have lower Bakken Shale over there. That's the Middle Bakken, of course laying there right on top of Three Forks over there. So we don't have that separating zone in it. But I don’t know that anybody has drilled a well on Three Forks to see if in fact oil was, of course, down there or not.

But Jack, maybe you want to respond to that?

Jack Stark

We had had the one task here that we were unsuccessful in establishing any commercial production on Three Forks now on the – kind of on the Northern end of our block. Yes. But in this business it is always tough to say never, because with these improvements that we are seeing as a result of completion practices out here, we are adding 10 stages, most of those wells out there were completed to open hole. And so, we are going from eight stages to 10, 14, now maybe 20, 24. It's really hard to say that we don't have a Three Forks potential out there, but time will tell.

Sven Del Pozzo – C.K. Cooper & Company

So you could apply the current development technology that you are using in North Dakota to the Montana acreage and perhaps see improvement in well performance?

Harold Hamm

And we have done that with the (inaudible) laterals in the Middle Bakken and it did work. So we have not applied that to the Three Forks out there.

Sven Del Pozzo – C.K. Cooper & Company

Okay. But I guess in – all in all, I mean I was thinking of Montana Bakken versus North Dakota is – in terms of the value, how would you look at it if you were going out there and trying to increase your lease position, would you – I mean, I'm trying to just pin down a little bit to gain a better understanding of the prospectivity that is on your Montana position since it does look like about 100,000 undeveloped acres out there.

Jack Stark

Okay. Certainly the most clear upside that we have in the Montana Bakken at this time is our in-field drilling on a 320-acre space and we still have about 50-some wells to drill there. And then to expand into the undeveloped position that we own out there, we – we've done and gone as far as we felt we could economically. With increasing prices and improved technology, we might be able to expand the extension of the field up into this undeveloped leasehold. So – I mean, that to me is kind of our position on Montana in a nutshell.

Sven Del Pozzo – C.K. Cooper & Company

All right, thank you, gentlemen.

Harold Hamm

Thank you.

Operator

Thank you. Our next question will be from the line of Leo Mariani. Please proceed.

Leo Mariani – RBC Capital Markets

Hi, good morning here, guys.

Harold Hamm

Good morning.

Leo Mariani – RBC Capital Markets

A question, in your point on your backlog of oil, you guys commented you had a lot of oil tanks, as well as in line fill. The curious inventing going on infrastructure-wise looks like that's kind of been building a little bit recently and can you comment on why you guys all that oil out there?

Harold Hamm

Well, we felt like that oil was cheap, very cheap in the first quarter and so, we just left it out, then sell it on into market later on and we did that and moved, I think, all of that or most of it in August.

Jack Stark

Moved about 120,000 in August and we've got the other that we’ve rolled out into the fourth quarter.

Harold Hamm

And rolled some other forward. But then when we talk about the capacity up here, we see today in a pipeline capacity and general capacity serving this Williston Basin area that we are working, there are about 100,000 barrels of excess capacity up there at this time and that takes in rail capacity that's been added. We've heard that EOG has a project up there at about 60,000 barrels – or is adding, I guess, 60,000 barrels per day of rail capacity. And then with the existing pipelines that came on that we see about 100,000 barrels.

Jack, you may want to add something to that?

Jack Stark

That pretty well covers that. Looking at the short term, Enbridge has announced about 51,000 barrel expansion that will come on in early 2010 and then at the same time, we've heard EOG's rail capacity is going to be in a range of about 60,000 barrels a day.

So combined, those are about 110,000 barrels equivalent of additional takeaway capacity that will exist in the Basin that hasn’t existed in the past and all of that is supposedly going to happen in early 2010. So we think that the takeaway capacity is going to keep up with growth out of here and right now, without it, it would seem like it's an exceeding growth or at least what we are seeing as far as production growth right now, rig count has been cut in half up there.

So it will take a little while for it to turn around, but once it does it looks like production is out in front of it. And so, anyway – or I mean, the pipeline capacity is out in front of it and that's a good thing for us and should maybe help us on our differentials a little bit here in the winter months.

And then I might mention too, there is also other capacity expansions that have been discussed and put out there by Enbridge – Enbridge in particular, reversing the portal system. That will add about another 30,000 barrels a day probably, say, in 2011 and then they are also looking somewhere out there later, 2012, '13 doing some additional expansion about maybe 5,000 barrels a day. So – anyway, I think that the capacity issues seem to be taking care of themselves.

Leo Mariani – RBC Capital Markets

Okay. I mean, you guys still leasing acreage up there on the Bakken or you think you've got kind of as much as you can handle at this point?

Harold Hamm

Now, Tom Luttrell is here. He may want to comment on it, but I think our number this year is about 30,000 acres that we've picked up additionally.

Tom Luttrell

That's correct, Harold. We've been both maintaining our position with lease renewals and also acting aggressively picking up more leasehold in the play. Harold is correct. We've picked up about an additional 30,000 acreage so far this year and/or leasing in the play right now where we can't.

Leo Mariani – RBC Capital Markets

And what kind of a term is associated with that lease? You guys are getting like five-year leases on that stuff or can I get some color on that?

Tom Luttrell

The term, it just depends on the areas, on the planks of the play, you are able to get five-year leases, but a lot of it's three. State's five-year leases, the BLM leases are 10-year leases or it's a mixed bag that we are able to get a good term and the bonus rate, but I'm – I prefer not to go into them for competition reasons. We are seeing those stay in an area that we still feel like is very good.

Jack Stark

Yes. And we've been successful in picking up some key acreage out here. And so this isn't just fringe acreage that we are picking up, but we've got some key acreage that we've been picking up and we are – so we are having good success out there with our program.

Leo Mariani – RBC Capital Markets

Okay. Any plans to restart the Michigan oil drilling program anytime soon given the rise in oil prices?

Harold Hamm

Obviously, that’s a program that has a great deal of potential and we’ve got a lot of undrilled, good-looking prospects up there and it's kind of take it back I guess to a little bit of the stuff we certainly felt like we had to drill and maintain up here in North Dakota, but that's still very much on the play.

Leo Mariani – RBC Capital Markets

Okay. Anything in the Haynesville? You guys leasing anymore, do you have any drilling results?

Harold Hamm

We are putting together a – well, we have about five drilling locations, five units right now, drilling space and units. And so those are the going at this time.

Leo Mariani – RBC Capital Markets

Okay. Have you guys started to drill at all in Mercer County, Bakken?

Jack Stark

Actually, we've just moved the rig in on our first test out there and are starting to drill.

Leo Mariani – RBC Capital Markets

Okay. So I imagine on the next call we'll hear about that?

Jack Stark

Yes.

Leo Mariani – RBC Capital Markets

Okay. Thanks, guys.

Jack Stark

Thanks, Leo.

Operator

Thank you. Our next question will be from the line of Ronnie Eisenmann [ph] from JPMorgan. Please proceed.

Ronnie Eisenmann – JPMorgan

Good morning, guys.

Harold Hamm

Good morning, Ronnie.

Ronnie Eisenmann – JPMorgan

You were able to grow production 30% in North Dakota using three rigs. What your expectation going forward the next two quarters and in the fourth quarter as you start adding to your rig count there?

Harold Hamm

Well, we like to say that we grew all that production with three rigs, but you recall last year we had I believe 32 rigs up there. So part of this help has been from completions of several of the well. So – go ahead, Rick.

Rick Muncrief

Yes, I think we had 13 to 14 rigs running in the Bakken last year and when you go – when you drop down to one rig, obviously you have a big inventory of completion that you built up overtime and I think the numbers in the first and second quarter, especially the second quarter reflect that.

Ronnie Eisenmann – JPMorgan

So how many wells in the second quarter were completed out of an inventory that was built up previously? Do you expect it going – like how many – how much do you have in inventory now relative to what you had at the start of the second quarter?

Rick Muncrief

Well, I think what you see is we burnt that inventory down over the last two quarters. And so I believe that we had 14 completions gross.

Jack Stark

Yes, right now what we've got out there, Ronnie, is we’ve got 14 gross and 4.2 net wells that are either drilling or in some stage of completion.

Ronnie Eisenmann – JPMorgan

Okay. And then –

Rick Muncrief

And that would include non-ops, okay?

Ronnie Eisenmann – JPMorgan

Okay.

Rick Muncrief

This isn’t just Continental-operated wells.

Ronnie Eisenmann – JPMorgan

And when do you guys expect to start utilizing the ECO-Pad drilling in North Dakota?

Harold Hamm

Well, like we said, we've changed that concept here internally and we've been working to reposition, resize wells. And so that’s going on and it looks like it's going to be – we thought we could do it third quarter, it looks like it's going to be fourth quarter, we believe, this year. So that’s what we are shooting for anyway.

Ronnie Eisenmann – JPMorgan

And will you be able to drill 10,500 feet laterals in wells that aren’t on ECO-Pads?

Harold Hamm

Well, if we went in individually and started drilling at this time, yes, we could. The regulatory authority out there gave us approval to drill that length. So we have no setback requirements up there within those units. So we can drill fence to fence whether it be on ECO-Pad or single well, but – at this time. We would like to employ ECO-Pads concept drilling those.

Ronnie Eisenmann – JPMorgan

Okay. And the last question are you guys planning on doing any additional companion well tests like the Mathistad, but across different parts of your acreage in the near term?

Harold Hamm

No, we don't. We have no plans for that. There will be additional information coming out over the next few weeks on – as production goes forward on both these wells. So this is not the end result of all this, but anyway it's very extreme, it's not logical that we would do that and fill the application but it was an important research project we felt like, both for Continental and for the state of North Dakota. And we felt like we ought to take that out and do it and we did it, it worked and it's economic and got a lot of information from it too. So we feel good about it.

Ronnie Eisenmann – JPMorgan

Okay. Thank you, guys.

Harold Hamm

Yes, thank you.

Operator

Thank you. Our next question will be from the line of Mitch Wordsmith [ph]. Please proceed.

Mitch Wordsmith

Good morning, guys.

Harold Hamm

Good morning.

Mitch Wordsmith

Just on the last question, so I guess no updates to 2009 production guidance at this point?

Harold Hamm

We do not at this time.

Mitch Wordsmith

Okay, great. And then I guess with you guys increasing your CapEx and where oil is now, would you guys look at putting any hedges on for oil or at least floors?

Harold Hamm

Yes, we look at it. It’s up and getting to a range that we feel like we need to work with. So we are going to be seriously considering it, try and look at all the parameters around it as we go forward here in the next few weeks. So we are certainly not ruling it out.

Mitch Wordsmith

Okay, great. And then any thoughts towards 2010 CapEx or still too early at this point?

Harold Hamm

Well, we think it's early, we just got this rolled out, but it all depends on price and certainly as oil prices get stronger – our expectation is that they will if oil prices do get stronger, we are entirely flexible and we'd quickly I think obtain approval to extend that budget.

Mitch Wordsmith

I appreciate the answers. Great quarter, congratulations, guys.

Harold Hamm

Thanks very much.

Operator

Thank you. And our next and final question will be from the line of Subash Chandra. Please proceed.

Subash Chandra – Jefferies & Co.

Yes. A clarification on how many wells per month do you think that 45 to 20 and change days translates into one well per month per rig in the Bakken?

Jack Stark

That's pretty close.

Subash Chandra – Jefferies & Co.

Perfect, great. Thank you.

Harold Hamm

Yes.

Operator

And at this time, we have no additional questions. I'll turn the call back over to Mr. Hamm for closing remarks.

Harold Hamm

Okay. Good morning. Again, thank you for joining us, good questions. One comment I want to make on cost here. As we said here, we've seen about 20% lowering of cost up here drilling. We think these ECO-Pads will add about another 10% and lot of you know we've been working our pipe and inventory and tubular inventory that we've had and that's pretty much gone at this time and we think our costs come down perhaps another 10%. So I think we gave everybody about a 40% number early on and – that we thought we could – we are shooting for in this cost reduction and I think we'll get there before this is over.

Obviously, we had a good quarter and a very important three months for us and with this successful completion at Mathistad 2 and – as I said, we are going into development mode including both these zones, Middle Bakken and Three Forks. We've got an innovative development approach and using these ECO-Pads I think will improve not only costs, but also production and operating efficiencies going forward in the long term.

So we think this is the way to go and we’ve got a good budget year that we've expanded to support this drilling and accelerate our drilling momentum going into 2010. So we see a good, bright outlook for Continental. A lot of potential in this play and we appreciate everybody's continued support as we continue to achieve our goals going forward. So thank you very much.

Operator

This concludes today's presentation. Ladies and gentlemen, we thank you for joining. You may now disconnect.

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Source: Continental Resources, Inc. Q2 2009 Earnings Call Transcript
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