Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

Executives

Harold Hamm – Chairman and CEO

Jeff Hume – President and COO

Jack Stark – SVP, Exploration

Rick Muncrief – SVP, Operations

Tom Luttrell – SVP, Land

Analysts

Michael Jacobs – Tudor, Pickering & Holt

Subash Chandra – Jefferies

John Freeman – Raymond James

Leo Mariani – RBC Capital

Brian Cusma [ph] – Wise Motor Strategy [ph]

Mitch Wurschmidt – Keybanc

Stephen Berman – Pritchard Capital Partners

Sven Del Pozzo – C.K. Cooper

Joe Allman – JP Morgan

Andrew Coleman – UBS

Continental Resources, Inc. (CLR) Q4 2009 Earnings Call Transcript February 25, 2010 10:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the fourth 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 the company’s fourth quarter achievements and 2010 outlook. He will be followed by President and Chief Operating Officer, Jeff Hume who will provide additional detail on financial and operating results and plans for 2010.

Finally in the question-and-answer period, several additional members of management will be available to answer your questions; including John Hart, Chief Financial Officer; Tom Luttrell, Senior Vice President of Land; Rick Muncrief, Senior Vice President, Operations; and Jack Stark, Senior Vice President, Exploration.

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

Harold Hamm

Good morning. Thank you for joining us today. As we announced this morning, Continental completed 2009 with positive momentum, capping off a year of excellent operating and financial achievements.

I would like to review our achievements and focus on how they positioned Continental for firm growth in 2010 and 2011. I am particularly proud of five accomplishments that set the stage for accelerated growth and production, cash flow, and value for our shareholders. We increased proved reserves in 2009 by 62% to 257.3 million barrels of oil equivalent compared to year-end 2008. Two-thirds of our proved reserves are crude oil. We delivered total production of 13.6 million barrels of oil equivalent in 2009, a 13% increase over 2008. The key to this accomplishment was North Dakota Bakken, where we doubled production last year to 2.4 million barrels of oil equivalent.

We are unveiling today our large strategic lease position that we have assembled Anadarko Woodford shale and our outlook for this play. I know there has been a lot of investor interest in Anadarko Woodford recently and we are finally in a position to talk specifically about our plans and to announce a powerful horizontal Woodford shale well that we have completed in Dewey County, Oklahoma, some 40 miles northwest of Cana Field.

The ramp-up in drilling activity as we committed has proceeded smoothly. We now have 15 rigs company-wide with plans to deploy 9 more by midyear. Finally given Continental’s excellent inventory of high-valued assets, particularly in the oil-rich Bakken, we announced this morning a 31% increase in our 2010 CapEx budget to $850 million. We plan to invest almost all of the incremental funds in drilling CapEx. Taken together these accomplishments set the stage for accelerated growth in production reserves in value creation for many years for Continental. These are exciting times here at the company and stark contrast to where we were last year.

This is especially true when you consider where we were only a year ago. In early 2009, our drilling program and the entire energy industry really were on a rollercoaster with drilling programs disrupted by the effects of worldwide recession and collapsed commodity prices that we were experiencing then. We successfully pulled back to stay in line with cash flow and then rigs all ready when crude oil prices rebounded in the third and fourth quarters. Our operating teams did an excellent job of adapting and today, we are back to 15 operated rigs with 11 of those in North Dakota Bakken and one in Montana. Within just at rig sell rate activity however, last year, we seized the opportunity in the downtown to significantly improve the efficiency over drilling and production operations.

In North Dakota, we kept the average drilling time of 45 days from spud to rig release, in 2008 it was to 28 days in the first half of 2009 and 26 days in the fourth quarter of 2009. We also improved the efficiency of our frac operations. One of our teams recently completed a 24-stage frac job in North Dakota in just 66 hours, less than three hours per stage. That’s a tremendous achievement, especially given the severe winter weather up there and wind blowing in ambient temperature setting on zero. Along with working more efficiently, we consistently improved the well productivity, especially in North Dakota Bakken.

In the fourth quarter of 2009, our initial production averaged 1,070 barrels of oil equivalent per day over a seven-day test period, 41% better than third quarter of 2009, and 96% higher than the fourth quarter of 2008, again a tremendous achievement. We ended 2009 with a new record well for Continental and North Dakota Bakken, the Hendrickson Number 1-36H in northeast McKenzie County, with 1,990 Boe average for seven days with a flowing tubing pressure of 3,000 psi. It’s a huge well on a very productive development area for Continental.

And by the way, we began 2010 with another well, the Hawkinson 1-22H in Dunn County, North Dakota, which produced 1,667 Boepd in its initial seven-day production test. Currently, this well is now flowing at 3,200 psi on its 1,460 [ph] port show as capable of much more than current volume of 1,200 Boepd, if not restrained to capture the entire gas volume produced. And the same goes, good fields keep getting better overtime and as certainly is the case with North Dakota Bakken.

Summing up for 2009 and proven it’s in operations in well results, resulted in record production of 13.6 million Boe for the year, beating our original guidance and our updated guidance in the second half.

The next strategic milestone was a growth for a proved reserves at yearend 2009 to 257.3 million barrels of oil equivalent, a 62% increase over yearend 2008. This begins to define a huge extent of Continental’s future growth opportunity. Changes in SEC reporting rules have enabled us to better reflect the tremendous potential we have in continuous accumulation plays and are drilling successes, particularly those in North Dakota, also contributed significantly due to the increase in proved reserve numbers.

Beyond the numbers, I however would like to focus on the asset value of Continental’s proved reserves and developed acreage. First, our reserves are 67% crude oil. In the North Dakota Bakken, we have 106 million Boe of proved reserves which is 41% of the total. This is five times the reserves in the North Dakota Bakken that we reported to you just a year ago.

Second, we anticipate significant additional reserves growth as we continue ramping up drilling. We plan to have 16 total rigs in the Bakken by midyear, with 15 of those active in North Dakota. At midyear, we plan to have six operated rigs focused on more efficient ECO-Pad development drilling and 9 rigs further delineating the play. We are currently drilling our first ECO-Pad site as we promised. Company-wide, we plan to have 24 operated rigs by midyear. This will allow us to maintain momentum in reserve growth.

Obviously, the new SEC rules have a huge impact on continuous accumulation play like the Bakken and better reflect the value of our play leading acreage position and active drilling program. However, even with the revised SEC rules, our proved reserved analysis contains only a small fraction of our undeveloped acreage in key shale plays. Included pads, 2009 proved reserves are 1,118 gross, 436 net proved undeveloped locations, more than half of which are in the North Dakota Bakken. 401 gross, 100 net PUDs in the Arkoma Woodford shale play in southeast Oklahoma and of note, we only have six gross, 3.5 net wells in the Anadarko Woodford shale play.

Not included in the reserve report were tremendous assets yet to be developed. For example, 91% of our undeveloped acreage in the North Dakota Bakken, 98% of our undeveloped acreage in the Montana Bakken and 98% of our undeveloped acreage in the Anadarko Woodford shale play were not valued in the reserve report.

Our drilling and development program obviously has a huge amount of running room with decades of development ahead. The final exciting news I would like to discuss with you is unveiling of our strategy in Anadarko Woodford shale play. The success of the Brown 1-2H horizontal Woodford shale well in Dewey County indicates to us that the Cana Field’s prolific, productive, potential expands on 40 miles northwest of the area developed today vastly expanding the Cana scope. Thus far, Continental has had two excellent horizontal Woodford producers and has expanded portion of the play, the Young 2-22H on the western side of the Cana Field and the Brown 40 miles northwest of the Young.

In the past two weeks, Anadarko Woodford producers who reported before us have discussed how prolific the play is, yielding natural gas condensate natural gas liquids. Almost all of the drilling experience has been in what they consider the core of the play. We believe we have expanded that core significantly. The Brown 1-2 IPed at 4.2 million cubic feet of gas to 102 barrels oil per day, even though the well was initially pipeline constrained has produced 455 million cubic feet of gas and 7,700 barrels of oil in its first five months online.

Although Continental’s data points are limited, industry results in the Cana Field today have been very positive with initial producing rates of up to 8.6 million cubic feet equivalent of natural gas per day and reserves of 8 to 11 Bcfe per well being reported. Our initial economic model assumes reserve for typical Anadarko Woodford well of at least 45.4 gross Bcfe per day per well, based on this model on 160-acre spacing development, Continental’s unrisked net potential in the Anadarko Woodford could range up to 5.5 Tcf or 900 million barrel oil equivalent.

Of the 200,000 net acres in the Anadarko Woodford shale play, we have 124,000 net acres in the area we refer to as northwest Cana, which includes 43,700 net acres in what other operators define as the core Cana. The remaining of our position, 76,000 net acres is in the area of we refer to as southeast Cana, extending in the southeast of the core Cana and the portions of Caddo, Grady and McClain counties.

In Southeast Cana, we are currently completing our second test well of Ballard 1-17H in Grady County. As we said this morning in our press release, we believe the Anadarko Woodford shale play is much larger in scope than previously described. We think it will be capable of competing with the economics within a shale play in the United States and is right at home for us within the Oklahoma base producing area. We see our position there as another critical building block in Continental’s long-term growth.

With so many excellent growth opportunities and a continuous strength in crude oil prices, Continental’s Board of Directors has increased our 2010 CapEx budget 31% to $850 million, enabling us to accelerate drilling in North Dakota Bakken and the Anadarko Woodford. The incremental CapEx spending is targeted for investment in the second half of the year and will provide increased momentum as we enter 2011.

To sum up, we are very excited at the immediate and long-term opportunities to accelerate growth in production, reserves and value creation for shareholders. Our commitment to you is that we will realize these opportunities and deliver exceptional results.

With that, I will turn the call over to Jeff.

Jeff Hume

Thank you Harold. I would like to take a few moments to drill down play by play discussing our results for the fourth quarter and calendar year 2009 and our outlook for 2010. The Bakken play continued to deliver excellent results during 2009. Our Montana and North Dakota Bakken production combined grew 31% over 2008 in spite of completing 20% fewer net wells than we did in 2008.

Our total Bakken proved reserves at yearend were almost three times higher than proved reserves yearend 2008. This includes an inventory of 681 gross, 306.6 net PD locations in the Bakken identified for future drilling. We continue to control one of the largest leasehold positions in the Bakken play, the 652,000 net acres today, which is an increase of 71,000 net acres over yearend 2008. We have 489,000 net acres in North Dakota and approximately 19% of that acres is now held by production.

During the year, we completed 104 gross, 35 net wells in the Bakken play, with 90% [ph] of the net wells located in North Dakota. Accordingly, North Dakota accounted for most of our Bakken growth. Our net production in North Dakota grew to an average daily rate of 8,578 barrels of oil equivalent in December 2009, up 60% from the average daily rate in December of 2008. Our proved reserves in North Dakota grew to 105.5 million barrels of oil equivalent by yearend 2009, up an impressive 503% year-over-year in 2008.

On top of the production reserve growth, we had several other pivotal achievements in the North Dakota Bakken during 2009 that will benefit us for years to come. We have substantially derisked our Nesson anticline acreage, allowing us to move into the development on much of this acreage. Our pioneering efforts demonstrated that the Three Forks is a separate reservoir for the Middle Bakken, adding a second reservoir and significant incremental reserves for future development. As a result, we had 616 gross, 261.9 net proven undeveloped locations identified for future drilling at yearend 2009 based on 640-acre spacing.

As Harold mentioned earlier, the key point here is that these proved undeveloped locations represent only 9% of our total undeveloped acreage in North Dakota. When combined with the 19% of our acreage that is developed, our total proved reserves affect only 20% of our North Dakota Bakken acreage position, leaving tremendous potential for future growth. Initial production rates of our wells increased during the year, especially our operated wells, due to improved completion technology and evolving geologic perspectives. The seven-day average initial rate for wells completed in the fourth quarter of 2009 was 1,070 barrels of oil equivalent per day compared with 546 barrels of oil equivalent per day for wells completed in the fourth quarter of 2008.

During the fourth quarter of 2009, our Hendrickson 1-36H, in which we own 95% working interest, produced at an average rate of 1,990 barrels of oil equivalent per day during its initial seven-day test period. This is the highest rate recorded from our operated wells as of 2009. Based on historical well performance, we also increased our expected reserve model to 430,000 barrels of oil equivalent gross per well with 14-stage frac completions. Our completion technology continue to evolve during the year and we are now utilizing 18-stage fracs standard treatments for wells. We are currently testing 20 and 24-stage fracs in some of our wells will make adjustments as we continue to seek the optimum treatment for our Bakken wells. On the cost side, drilling efficiencies developed and implemented by our technical staff during the year continued to improve rates of return as Harold noted.

Our average spud to rig release was 26 days in the fourth quarter of 2009, down from 45 days for the same period in 2008. We completed well cost by 28% in proved rig utilization. We reduced production cost for barrel throughout the year. For the fourth quarter of 2009, our production expense per barrel of oil equivalent was $6.71 versus $7.83 in the fourth quarter of 2008, a 14% improvement. In terms of full-year numbers, we averaged $6.89 in 2009 compared with $8.40 in 2008, an 18% improvement. A $6.89 per Boe in production expense for 2009 was $0.86 below the bottom of our guidance range for the year.

Our operations team did a great job managing cost in a volatile competitive environment. Overall, this past year, we analyzed our operations in the slowdown, adopted best practices and improved our results, and we continue to improve it. During 2010, our revised $850 million CapEx budget, we plan to invest $479 million drilling 218 gross, 80.5 net wells in the North Dakota Bakken. This will include development wells with our Nesson anticline acreage and step out wells designed to expand productive areas and further derisk our undeveloped leasehold. To date, almost all of our drilling has been on 1,280-acre spacing, targeting either Bakken shale or Three Forks reservoirs.

Our development drilling in 2010 will continue to focus on developing both the Bakken and three Forks reservoirs and will include a combination of 1,280-acre proved undeveloped locations and 640-acre in-field locations. In time, we expect to develop the North Dakota Bakken field on 320-acre spacing like the Elm Coulee Field in Montana. We plan to invest 34 million, drilling 14 gross, 6.8 net wells in Elm Coulee Field in Montana during 2010. Drilling will be focused primarily on the 65 gross, 45.1 net proved undeveloped locations identified in the field. We will also be working to expand Elm Coulee Field using multi-stage frac completion technology that we developed in North Dakota.

We recently completed the Rognas 2-22H using this approach. The Rognas in which we have a 95% working interest, tested 841 barrels of oil equivalent per day during its initial seven-day test period. This is more than twice the rate observed from offsetting wells that were completed using open-hole frac technology. At yearend 2009, we held 97,350 net undeveloped acres adjacent to the Elm Coulee Field for potential expansion using this technology. We currently have 11 operated rigs drilling in North Dakota and one in Montana and plan to have four more operating in North Dakota by midyear 2010. Of note, we have begun drilling our first ECO-Pad site in North Dakota and are rigging up on the second. As you may recall, the ECO-Pad sites allow up to four wells to be drilled from a single pad, reducing the environmental impact of drilling cost, while increasing crude oil recovery with longer lateral well bores.

We plan to have six ECO-Pad rigs drilling development wells in our Nesson anticline acreage by mid 2010. Switching to the Anadarko Woodford, as we announced today, we increased our acreage position in the emerging Anadarko Woodford play to approximately 200,000 net acres. This includes 51,500 net acres leased since yearend 2009. This investment reflects our broader perspective that the true productive areas of the Anadarko Woodford goes well beyond the Cana Field. This was confirmed by results for our exploratory Woodford shale test drilled approximately 40 miles northwest of the Cana and Dewey County. This well called the Brown 1-2H, which we own 100% working interest has been producing for approximately five months and is producing every bit as well as our Young 2-2H, which we completed on the western edge of the Cana Field in September of 2009.

The Brown started producing at 4.2 million cubic feet of gas and 102 barrels of oil per day and has cumulated 455 million cubic feet of gas and 7,700 barrels of oil in its first five months online. The Brown currently produces an average rate of 3.2 million cubic feet a day and 52 barrels of oil per day. The Young 2-22 initially produced 6.8 million cubic feet of gas per day and has accumulated a total of 750 million cubic feet of gas during its first six months online. It continues to float an average rate of 4 million cubic feet of gas per day. By comparison, these wells performing better than tighter by other operators in the Cana Field.

Approximately 65% of our acreage in Anadarko Woodford play is in the area we call Northwest Cana in Blaine, Custer and Dewey Counties, extending from the Brown well to and including the Cana Field. Approximately 23% of our Northwest Cana acreage is held by production. The remaining Anadarko Woodford acreage is located in the area we call Southeast Cana, also including parts of Caddo, Grady and McClain counties. In Southeast Cana, we recently drilled and are testing the Ballard 1-17H horizontal Woodford well in Grady County. In 2010, we plan to invest 39 million, drilling 15 gross, 7.3 net wells in the Anadarko Woodford play, as we continue to delineate productive expense of our leasehold. We currently have one rig drilling in Dewey County and plan to add two additional rigs in the play this summer.

Moving to the Arkoma Woodford, in our established Arkoma Woodford play, fourth quarter production was up 9% over fourth quarter 2008, and annual production was up 69% over 2008. At yearend 2009, we had 21 gross, 3.1 net wells waiting on completion. During 2009, we completed the total of 71 gross, 8.5 net wells, which compared with 130 gross, 24.6 net wells completed in 2008. Our 2009 completions include a combined combination of 640-acre exploratory and 80-acre in-field development type wells.

We continue to use simul fracking when possible to more effectively stimulate produce the Woodford shale or causing minimal disruption to existing offsetting producing wells. In the past year, we also acquired 63 square miles of 3-D seismic data, which will provide critical guidance to our exploration development drilling in the East McAlester area. At yearend 2009, we had approximately 44,800 net acres under lease in Arkoma Woodford play. We have added to that position in early 2010 and now have 47,500 net acres. Approximately 47% of this acreage is held by production and contains a total of 401 gross, 100.3 net proven undeveloped locations for future drilling.

For 2010, we plan to invest 56 million to drill 58 gross, 12 net wells in Arkoma Woodford play. Approximately 46% of the drilling capital was targeted for development drilling, with the balance focused on strategic step-out and exploratory drilling designs to secure acreage and delineate productive areas for future development. We currently have one operated rig drilling in Arkoma Woodford play and expect to keep two rigs drilling in the play much of the year.

Red River Units, our second area of recovery program in the Red River Units continues to perform well generating production of 14,249 barrels of oil equivalent per day for the fourth quarter of 2009. We expect production to peak at approximately 15,500 barrels of oil equivalent per day in the second quarter of this year. 2010 plans include 11 new producing wells and one reentry well, in addition to converting 25 producer and air-injection wells to water injectors. We have allocated $70 million of CapEx to the units and we revised CapEx budgets split evenly between drilling CapEx and investment in workovers and facilities.

Before I turn the call back to our moderator for Q&A, I would like to provide some additional color on our production outlook. On November call, we provided production guidance for approximately 10% in 2010. In today’s release, we increased that target to approximately 13%. As we have said before, our long-term goal is to double our production reserves every five years, and the additional $200 million in CapEx that we announced this morning is another step in achieving those results. As we said, it will primarily affect 2011 as we continue to build momentum assuming commodity prices are supportive. Speaking of which, this strategy involves hedges that we put in place recently. Instead of reviewing this on this call, I will refer you to the summary of crude oil and natural gas swaps in collars for 2010 and 2011 that we will provide in our 10-K when it is filed later today or tomorrow.

Please review those to get better visibility of our hedging position. With that, I will turn the call back to the operator for Q&A.

Question-and-Answer Session

Operator

(Operator instructions) Your first question comes from the line of Michael Jacobs with Tudor, Pickering & Holt. Please proceed.

Michael Jacobs – Tudor, Pickering & Holt

Hi, good morning everyone.

Harold Hamm

Good morning Michael.

Jeff Hume

Good morning.

Michael Jacobs – Tudor, Pickering & Holt

You mentioned 320-acre spacing in the wells basin, are you effectively saying four wells per 1,280-acre unit, is that the right way to think about it?

Harold Hamm

Yes, that would be four wells per 1,280 per horizon.

Michael Jacobs – Tudor, Pickering & Holt

Per horizon, okay. And so, just kind of back of the envelope map, does that suggest, I remember you have talked about 500 Bakken locations, 300 Three Forks, does that suggest that, that total inventory number could be closer to double that or maybe a little bit higher?

Harold Hamm

That is correct. We have not drilled any on the 320-acre spacing at this time. So, that would be, that potential would be to double that.

Michael Jacobs – Tudor, Pickering & Holt

And how do you think about the rig count over the next few years as you try to kind of dig into that inventory?

Harold Hamm

I think we will see an ever-increasing rig count just due to our strong acreage position. We are moving right now to 15 in the North Dakota Bakken, and we could easily accommodate 20 today on development. So, it’s mainly a cash flow restriction and just keeping in line with that, so as we grow our production in cash flow, I think you will see an ever-increasing rig count.

Michael Jacobs – Tudor, Pickering & Holt

Okay. On the evolution of your horizontal Bakken program and you mentioned the 18-stage completion is going to 20 to 24. For those 18-stage wells, how many reserves are you booking per location in kind of the 1-P [ph] reserve?

Jeff Hume

Right now, we are just staying with the 430,000 barrel model, which is our trailing average for the 14-stage model, and obviously we are seeing higher initial production rates with the 18-stage and even higher with the other higher stage fracs. So, it’s very early, you know, we just started doing 18-stage fracs last September. It’s really early in those well’s lives to be changing a forecast. I think intuitively we will be increasing that, but I can’t tell you how much. So, for the time being, we are staying with the 430,000 barrel model.

Michael Jacobs – Tudor, Pickering & Holt

Okay. When I looked at your guidance for North Dakota spending, the 480 million [ph], the 85 net wells, it’s kind of roughly 5.5 million per location, but the 200 million in extra spending, I think you mentioned that it’s all drill bit in the Williston, that gets me to $10 million per well, can you help me reconcile that?

Harold Hamm

I think we will have to get back with you. I think the 486 is – with the 200 million in, 850 million all of budget percent. Jack?

Jack Stark

Yes, I am looking at – you know, I don’t know what your well count is, we are looking at drilling in under the $850 million budget, 218 gross, 80.5 net wells, and we have got 491 million [ph], that’s in there for the North Dakota Bakken. And so, then that comes up around 6 million apiece and that actually carries as carrying cost coming from ’09, because we did ramp up our activity in late ’09. So, you are actually seeing at this portion of cost relative to completion just because of that ramp-up. But I think, you know, we should be looking at $5.5 million in parts of the Dunn County area and then up north we are moving at 4.8 million a copy and the ECO-Pads do give us almost a 10% discount on the typical cost of well.

Michael Jacobs – Tudor, Pickering & Holt

Great, thank you very much.

Jack Stark

Thank you.

Operator

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

Subash Chandra – Jefferies

Good morning. First just want to thank you for putting out one of the more comprehensive reserve releases we have seen. So, I hope that becomes more industry standard anyway. I hate to do this, but the $850 million, is it possible just to reiterate that, break it down by area again, I just want to make sure my numbers added up, I am coming up a little bit short?

Jeff Hume

Sure. Just so what I am doing here is I will give you the land numbers, we have got 91.6 million, seismic 8.5, and other we have got 12.2. And as far as straight up drilling North Dakota Bakken, 490.8; Red River Units, 70.3; Arkoma Woodford, 56.8; Montana Bakken, 42.8; Anadarko Woodford, 39.1; emerging plays, I have got a – some of these other plays are lumped together, but we will have what we call emerging plays 16.6, our Mid-Continent area 9.4; Rockies and other type of things, 6.3; Gulf Coast area, 3.9; and up in our willing project, we have got 1.7. So, that all totals up to $850 million.

Subash Chandra – Jefferies

Perfect, thank you. With the delta being the 200 delta as far, I think the last question was all North Dakota.

Jeff Hume

Yes, we have got 80% of the increase going into drilling in North Dakota.

Subash Chandra – Jefferies

Okay, perfect. All right. In North Dakota, you know, have you thought about, I mean with how little is developed and how all these wells are paying out, and the stuff, you know, how is this talking about, St. Mary’s simul frac etcetera, I mean, do you see a scenario where you can do simultaneous development of Three Forks in Bakken and you know, how you think about perhaps accelerating production there other than just ramping the rig count?

Harold Hamm

Well, I think that this write-in with ECO-Pad development is we are going to have these rigs drilling a Middle Bakken lateral and an offsetting Three Forks lateral, which will definitely set us up for potentially simul fracking, those two laterals taking advantage of that horsepower concentrated in a small area. That’s one area we will be working on in the coming year to establish if that’s a true gain or not. From our experience in the Arkoma, it’s going to be somewhat different here as we are working different offsetting horizons, but I think it’s something to really look at to strive forward. So, you are point on there with your question.

Subash Chandra – Jefferies

So, you have done, you have come back to areas where you have drilled the Bakken, you have come back – I am sorry, Three Forks, as you come back, you drill the Bakken, I think there was perhaps another set of pairs of wells that you have done that with any particular update there and have you done a simul frac yet and if not, is that sort of a Q1 event?

Harold Hamm

Yes, in one of our areas, the well, we actually we are very encouraged when we came back in and drilled the Bakken. So, we have a virgin pressure and very, very encouraged by that, that’s a 660-foot [ph] offset between the bias, I assume between the Three Forks and the Bakken.

Subash Chandra – Jefferies

Was there another pair that you are working on? Were you coming back to a Three Forks?

Harold Hamm

The Omar, yes, that’s right, the Omar 1 & 2, and we are still testing the capability of that, we are very, very encouraged.

Subash Chandra – Jefferies

Okay, but no simul fracs yet?

Harold Hamm

No simul fracs at this point.

Subash Chandra – Jefferies

Okay, great. Anadarko Woodford, so it looks like you still, you are looking sort of at you know 5 million a copy, 5 million to 6 million a copy. And so how would you say, you know, what happened with perhaps this well, I mean, your tone has changed quite a bit. Is it from complete, different ways in completing the wells or did you find something maybe geologically consistent to the core and/or confidence sort of dealing with oil in a tight reservoir.

Jeff Hume

Subash, I think if you remember back about two years ago, we had a test out there called the Barwoods [ph] in the same area that our Brown well is, and we had some mechanical problems with that well, you know, back then, we drilled through (inaudible) section in the Woodford. However, we had the pressure, we had the initial flow rates just towards the section and it gave us the indication that we were in a nice productive area, if we could drill the well successfully and we came back and did that. You know, it has been two years ago and since we drilled Barwoods, and of course the Young well, you know, we were very satisfied with the outage, we called it, it was outside of the core area as the operators call it. Then we stepped up and drilled this Brown well, it was very successful and since then, we have been taking leases out there, and you know, this Brown well is just half a mile away at Barwoods well for instance. So, we are in the same neighborhood. So, this was a confirmation to us and you know, we are very excited about it obviously.

Subash Chandra – Jefferies

Yes. And comparing it to the core, how is it different I guess in terms of maybe pressures, but is it depth and other particular metrics?

Jeff Hume

I will turn to Rick Muncrief.

Rick Muncrief

As far as the depth, we are slightly shallower, but only slightly versus the core Cana area. Pressures are slightly lower but pretty much in line with what we have seen up there in the Brown. Very encouraged, we had the well on for six months as Jeff mentioned. We made right at half of being, and when you sort of looking at the new oil production, we are very encouraged by that. We have been going into a constrained pipeline, and we are working on that to try to improve the productivity, of course, naturally we have been trying to increase our leasehold in that area, and we have done a great job in doing that.

Subash Chandra – Jefferies

You think you will have fairly predictable oil exposure well-by-well, or is that still something you figured out?

Rick Muncrief

We are still somewhat early in the play. We are working that. We have been pretty intrigued with what we have seen, both in the northwest part of the play and in the southeast part of the play. And I think Subash, you are just taking it to the – where there is a density of wells in the Cana Field, we are seeing the deeper, more mature rock or higher temperature rock, they are seeing lower liquid level and as they get a little shallower, higher, so there is going to be a band through here, that’s going to have real nice liquid recovery. This Brown well looks like it’s sitting right in that band, it’s got great productivity and making about 20 barrels of liquids per million cubic feet, and it’s been very steady at that rate, that production rate. So, really strong, so good chance, we will have a band, multi-miles wide coming across tying into Cana, that we will have a real strong oil component to it.

Subash Chandra – Jefferies

Great, congratulations, thank you.

Harold Hamm

Thank you.

Operator

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

John Freeman – Raymond James

Good morning guys.

Harold Hamm

Good morning John.

John Freeman – Raymond James

I want to drill down a little bit more on the North Dakota Bakken EUR assumption. Your 430,000, that’s the talk you have been out there for several months from you all with carrying your internal model, so I am assuming kind of Ryder Scott just kind of came along the same lines as your internal model. And I am looking at, you know, just kind of you know, back of the envelope, in ’08, you had 600 barrels on a seven-day rate and you are booking around 365. You have now, if I just take your fourth quarter seven-day rates, you are up about 70% from what you did in ’08, and the EUR number, you know, is going up maybe 18%. So, obviously, you know, I am thinking that number is pretty low, and I am just trying to get a sense of kind of the magnitude of how much that could go up here over the coming years. On your internal model type curve that you are using, kind of if you could roughly give me what your seven-day rate as you are basing that on?

Jeff Hume

Well, what we have, we have a first 30-day rate of around 430 barrels a day. So, we are obviously beating or model, you know, with these seven-day rates that we have shown in the fourth quarter average, we are beating that model. But again, it’s early, early time, John, and we hate to start predicting reserves on the early time production rate. We really need to see how they set in. We are putting more frac stages on here, which should give us very high productivity early on. The key is going to be, is it actually exposed more rock and get better drainage. We feel like it is from early data that is too early to be changing our models yet. You really need to have that, you know, a population of wells with 90 and 180 days of history on it to do that. We are going to stay on the conservative side and continue to look backwards. Our 430 model, to answer your question about Ryder Scott, when we built that, we did a statistical analysis of all trailing wells that we have had and fit that, and of course, Ryder Scott using pretty much the same fits that we had for the averages.

John Freeman – Raymond James

Okay, good. Yes, I appreciate your conservatism. I am just trying to get a sense of the magnitude of what we could be looking at kind of on a go-forward basis, as you get more and more drilling results. If I shift over to the differentials in the Bakken, obviously they end up coming kind of in a low end of the original guidance that you all gave last year. Just trying to get a sense of going forward, how to think about modeling that, obviously you have had quite a bit of takeaway improvements with, you know, the Enbridge expansion, the EOG rail system, and then we have got some portal line reversals over, you know, the next few years. Just kind of directionally, you know, and magnitude what you all are thinking about on differentials?

Jeff Hume

Well, you know, we had a very good year and part of that was just more space opened up to what the markets and markets improve. The takeaway capacity is strong for us, we are piping all of our barrels out. It’s not a large, large problem for us. I think we will continue to see that there is more oil it appears moving across on the XL line from Canada taking some pressure off from the express pipeline, it comes from honestly down into the Guernsey market. And so, that’s opening up a little bit stronger market at Guernsey, which was one of the big improvements and just the light oil that we have just is very good for these refineries for their yield, because there is just no throwaway part of it. So, we are starting to see the markets improve, and I think we will hopefully continue to see that with some of the Canadian syn crude and heavy crude moving across and filling that XL and Keystone line, we will see the Keystone pipeline, I think we will see a little less pressure at Guernsey coming through the express pipeline, and that should help our markets.

Harold Hamm

One other thing, on our horizon, John, is that the XL pipeline has proposed from (inaudible) down to through Cushing, and on down to Houston Belmont area. There is good chance that perhaps, you know, this Bakken well can be shipped on that line as well in the future. So, we are always looking long ways out ahead of us and how we can get additional barrels at the market in a big way. So, as this thing develops, you know, there is an awfully big line and we are meeting with them, March 3rd actually to discuss moving this all down to market on XL.

John Freeman – Raymond James

That’s very helpful, thanks. On the drilling ramp from 15 rigs to 24 by midyear, how many of those rigs have already been secured and just kind of directionally, what are you seeing on the rates on those rigs?

Rick Muncrief

We have, starting in the North Dakota, we have four more rigs secured that we will be picking up within the next five to six weeks. In the Anadarko Woodford, we have two more rigs, we are picking up. We will be picking those up in the next 60 days. On the rates up north, we are seeing anywhere from $14,000 to $18,000 per day on a day rate standpoint. And one of the things we are doing, we are bringing in rigs from other parts of the Rocky Mountain region, beyond the basin in Southwest Wyoming, where with the drop in activity there, we are able to bring those rigs in. The other thing that we like about that, those are the walking rigs if you will that will be utilized with our ECO-Pad development, and as Harold and Jeff mentioned earlier, we have the first ECO-Pad rig is currently drilling. We should spud the second pad rig tomorrow. And so, we will have four more that we will be bringing in, all of which have been secured.

John Freeman – Raymond James

Thanks a lot guys. I will turn it over to somebody else.

Jeff Hume

Thanks John.

Operator

Your next question comes from the line of Leo Mariani with RBC Capital. Please proceed.

Leo Mariani – RBC Capital

Hi good morning here guys.

Harold Hamm

Good morning Leo.

Jeff Hume

Good morning.

Leo Mariani – RBC Capital

Obviously, your fourth quarter initial production rates in the Bakken showed a pretty strong improvement from 3Q. Just trying to get a sense of how many of those wells you guys were using longer laterals and frac stages for, were you doing an 18-stage fracs on the vast majority of those and how much credit would you give to that?

Jeff Hume

I think most of those were 18-stage fracs for the fourth quarter for completions. We started that technique of running 18-stage in late third quarter. So, most of the fourth quarter completions were 18-stage fracs, and that’s probably some of the reason for that, we are also handling the amount of sand, includes we are getting in for stage, the guys have been working really hard on the stage design. The number of stages gets a lot of perhaps it’s easy to talk about, but we have worked real hard in getting more sand per stage in, it’s really paying off.

Leo Mariani – RBC Capital

Okay. In the Bakken, I know you guys have got something like 645,000 acres or so. Just trying to get a sense of, you know, what percentage of that you think you have kind of tested with wells at this point. I know you had a disappointing well in Mercer County and trying to get a sense of how much that acreage is possibly going to be condemned.

Tom Luttrell

Okay. Yes, Leo, this is Tom Luttrell. That tracks well down that area. We have about 70,000 acres down there, net general area, and what we call our Hayden and Romulus prospects that, you know, track is more or less on the far east side of that acreage block. But right now, we see 70,000 acres that we need to see some additional drilling on by other operators in order to allow us to class more on that block. And Leo, we haven’t condemned that yet. You know, we have real good production and good permeability in that zone, that was in the Stallion zone and we have got significant acreage in that block up from that, which potentially would be testing later on. And there are other operators within that area that have wells planned. So, we are just content on a cooler heels and watching other activity, probably planning another well up from this frac well. So, really I don’t think we are ready to condemn any of our acreage at this time, we are going to continue to look at it. Obviously it’s got higher risk than others, but as you could see from our reserve bookings, it does take a whole lot of acreage together, tremendous amount of bookings.

Leo Mariani – RBC Capital

Right. I guess, and what percentage of your 481,000 or so acres up there in North Dakota do you think you have capped it with wells this time, how much have you delineated?

Tom Luttrell

Capped – the numbers, Jeff, that you had –

Jeff Hume

Well, we booked reserves on about 28% of that. So, I guess that would be a way to handle that, and that’s what we announced. We have HBP, 19% of our acreage is HBP now by drilling, the PUD offsets took another 9%. So, what’s drilled and what we feel very comfortable is about 28% of our acreage and we are continuing to step out now. We have got several step-outs that are completing now and looking very favorable.

Leo Mariani – RBC Capital

Right, but I guess presumably, there has been industry activity, you know, in and along your acreage as well. So, I am just trying to get kind of a ballpark in terms of, you know, what you guys feel you know reasonably comfortable is going to be productive on that acreage?

Jeff Hume

I think right now just in general sense, I would say at least 75% of it, I am very comfortable with.

Tom Luttrell

Yes, I was going to say, if you add everybody else’s activity in there, I agree that, very high percentage, 75% is really in that more of a – it’s been derisked significantly here in the last six months.

Leo Mariani – RBC Capital

Okay, in your 2010 program, what percentage of your wells you are going to be targeting the Three Forks versus the Middle Bakken?

Jeff Hume

That’s going to be about 50-50, you know, with the ECO-Pad rigs, those well will be 50-50 and then we are just going to have a mix of Middle Bakken and Three Forks. I don’t think it would be weighted one way or the other, and just kind of depends on the area and where we are at. And what we are trying to do is build confidence in both horizons over broad area. So, as we move out with the delineation rigs, we will be checker boarding acreage if you will and testing both horizons.

Leo Mariani – RBC Capital

Okay, and I guess you guys obviously announced, you know, few really good wells in your press release like the Hendrickson and Hawkinson. Just curious whether those are Three Forks wells or Middle Bakken?

Jeff Hume

Those are Three Forks wells, they are both Three Forks.

Leo Mariani – RBC Capital

Okay. You obviously increased your CapEx a little bit this year. It sounds like it’s mostly back half weighted on the CapEx increase. Is it fair to assume that maybe you guys are looking at 325 million in the first half of ’10 and roughly 525 million in the second half, doing the math there?

Jeff Hume

That’s probably reasonable, because we are, you know, the first half, we are ramping up. We are going to be ramping up to around 24 rigs by May and holding that through the end of the year. So, that’s probably a pretty good model of what it’s going to look like.

Leo Mariani – RBC Capital

Okay. Last one, any update on the activities in Michigan in terms of any well reserves are laid or picked up any more acreage in your current inventory over there?

Jack Stark

We placed our Gordon well on the pump, you know, it’s productive, placed it on the pump, and we have plans to actually drill four more wells over the next few months.

Leo Mariani – RBC Capital

Okay. Thanks guys.

Harold Hamm

Thank you.

Jeff Hume

Thank you Leo.

Operator

Your next question comes from the line of Brian Cusma [ph] with Wise Motor Strategy [ph]. Please proceed.

Brian Cusma – Wise Motor Strategy

Good morning guys.

Jeff Hume

Hi Brian, good morning.

Brian Cusma – Wise Motor Strategy

Can I ask on the Montana well that you guys drilled just north of Elm Coulee, is that geologically more similar to Elm Coulee, or do you kind of liked the less complex basin center play?

Jeff Hume

That well, the Rognas well is, it’s not really north of Elm Coulee, it’s actually on the northern portion of the Elm Coulee Field itself. And so, you know, we are still, I guess you would say within the confines of the field itself there, but we are encouraged with the outcome and feel that bodes well for some additional future development out in that area.

Brian Cusma – Wise Motor Strategy

Okay. And then moving to Cana, the wells that you guys drilled there, did you use hydrofluoric acid or just the standard hydrochloric acid?

Rick Muncrief

Well, we just, we would lead with hydrochloric on the frac jobs. Yes.

Brian Cusma – Wise Motor Strategy

Got it. And I may have missed it, but in terms of the liquid content on your Cana acreage, how much of your acreage do you think is just going to be drag-out versus having some sort of condensate?

Rick Muncrief

Brian, it’s a little early to tell, but I think just from the public data that from the other players in the Cana property you are seeing, it go from dry gas on the southwestern side of their play to fairly high liquid content to the northeast side. So, there is going to be a band northwest, southeast band there, that grades from probably as high as 30 barrels of liquids per million down to dry gas or Young wells on the southern portion and it’s pretty much dry gas of that band, the southeast, the southwest portion of that band. The Brown well is probably in the middle of that band, it’s got about 20 barrels per million. So, you know, probably 75% of the – the liquid may be 80% of the acreage would be in the liquid portion, but it will not be consistent, it will grade depending on maturity, thermal maturity of the rock.

Brian Cusma – Wise Motor Strategy

Okay, now that makes sense. And like you compared your wells to other operator type curves, and I am just curious where, I mean, they have done our numbers anywhere from six to 10 Bs for 5 million or 6 million a day wells?

Rick Muncrief

Yes, they started out at you know 5 million a day, 4 million to 5 million a day and then at the end of the first year, they are typically in the minus 2 [ph] million a day and our two wells both have only about six months of production history that they have been flat in the 4 million a day equivalent range for six months. So, we feel very positive about our wells so far.

Brian Cusma – Wise Motor Strategy

And what is it about geologically that gives this play kind of that higher EUR to IT relationship?

Rick Muncrief

Well, you are dealing with depth, is one of the issues here. So, you have got higher pressures and more gas basically compressed per square mile. And you know, our technical teams have looked at this, the study of the Bakken, excuse me, the Woodford across Oklahoma, and you know, we have got a lot of experience with shales and spent several years working in the Arkoma Woodford play and based on their studies, you know, we see really the Woodford is one continuous reservoir across the Oklahoma that has varying degrees of thermal maturity and you know two of the biggest accumulations are in the Arkoma and the Anadarko basins. From these studies, they felt that you know, that we could actually expect to duplicate the results we have seen in the Arkoma Woodford in the Anadarko, the difference being is the Anadarko is substantially larger. So, we have a lot more potential for growth in the Anadarko. So, we see similar thickness of rock, similar thermal maturities and we are seeing similar outcomes, just increasing recoveries, I think based on depth.

Brian Cusma – Wise Motor Strategy

Okay, great. One last one from me, do you guys have a split on the – between developed and undeveloped?

Harold Hamm

We can get them to you. Brian, I don’t have that here at my fingertips. We do have a breakdown of that.

Brian Cusma – Wise Motor Strategy

Okay, thanks guys.

Jeff Hume

Thank you.

Harold Hamm

We will get that to you.

Operator

Your next question comes from the line of Mitch Wurschmidt of Keybanc. Please proceed.

Mitch Wurschmidt – Keybanc

Hi guys. Really most of my questions have been answered, but sorry if I missed this, can you talk a little bit about service costs in the Bakken, and what you are seeing and then kind of how much you have baked in to your CapEx for 2010?

Jeff Hume

Well, let me, I will address that. Currently cost estimates for a 22-stage frac job for completed Bakken Three Forks wells is $5.4 million, and we are keeping that relatively flat from last year. Primarily we feel that we have seen some slip in efficiencies slide as we ramped up nearing the winter season, but really have not seen a lot of cost pressures in the Bakken that you are seeing in some of the other areas throughout the US, and our rig rates have been fairly constant. We will see how that plays out, but we feel that we can hold a little on cost and we will be working diligently to do that.

Mitch Wurschmidt – Keybanc

And I assume you have a lot of contracts you kind of put in place. Is that really why you are seeing kind of flat costs? I mean, just with the activity pickup, it seems as if we probably see somewhat of an increase up there at kind of what we hear from other people?

Jeff Hume

Yes, I think what we are seeing is that the cost pressures on our projects are more around slipping efficiencies if more so than the cost of services. And so, with efficiencies, we will be getting better as we get few wells under the belt of each rig and feel pretty good about that.

Jack Stark

We are not quite back to the proved reserve [ph] in 2008 with rig count. We are just about to tie it just now getting back to that point.

Jeff Hume

And we are bringing new rigs into the basin, which I think is going to help us well.

Mitch Wurschmidt – Keybanc

Okay, great That’s really helpful. And then just finally, I know you talked a lot about the Cana, but on the Ballard well and kind of what you have seen on, can you just talk a little bit more about the southern end of the play and kind of what you are seeing differences down there versus maybe what you are seeing at the northern part?

Rick Muncrief

Well, we haven’t announced any results on the Ballard. We have fracked the well, we did a 15-stage frac on it, just now flowing back, we are going in to clean the lateral out today, which is standard completion procedure. So, it’s a little early to talk about it. From the McCalla well that we released last summer, we are seeing higher, much higher oil component to it. That well was producing, I believe we announced 50 or 60 barrels of oil or high gravity of oil and about 350 to 450 Mcf of gas if I memory is right. So, it’s a fairly high liquid component area. That’s one reason we really liked that area, we think we have very good liquid recoveries down there. And so, we are excited about the Ballard and anxious to see what its performance will be after we get the post-frac cleanout and get an IP on it.

Mitch Wurschmidt – Keybanc

The most acreage you guys had, was that more on the northern end or the southern end or kind of all over the place?

Rick Muncrief

Just mostly in the northern end. We had a pretty darn solid position in the southern end last year, last summer.

Mitch Wurschmidt – Keybanc

Great. Thanks for the answers, that’s all I have got.

Operator

Your next question comes from the line of Stephen Berman with Pritchard Capital Partners

Stephen Berman – Pritchard Capital Partners

Good morning guys. One clarification first, can you just repeat the five-month accumulation on the Brown well on the Anadarko Woodford, I might have misheard that?

Harold Hamm

The five-month accumulation is 455 million cubic feet and 7,700 barrels of oil.

Stephen Berman – Pritchard Capital Partners

I guess I have the numbers in the press release are different, that’s why I am asking, press release –

Harold Hamm

Yes, the difference is, we have updated the call, this is as of today, the numbers I just shared with you.

Jeff Hume

Yes, Steve, the numbers we have in the press release were polled from earlier production. We looked at the accumulation today and that’s where they are at, 455 and 7,700 barrels on that. 750 million cubic on the –

Stephen Berman – Pritchard Capital Partners

The numbers you just gave me were for the Young?

Jeff Hume

The 750 million cubic feet was for the Young and the 455 million cubic feet and 7,700 barrels of oil was from the Brown.

Stephen Berman – Pritchard Capital Partners

Brown, okay, good.

Jeff Hume

Yes. That’s accumulated up to today.

Stephen Berman – Pritchard Capital Partners

Yes, that’s more than five months in?

Jeff Hume

Yes, about five-and-a-half. We have been about six months there.

Stephen Berman – Pritchard Capital Partners

And then in North Dakota and Nesson, I know you were drilling at least one well in the general area where Brigham's had a lot of success, any updates on what’s happening in that part of the play from you guys?

Rick Muncrief

Yes, the Brigham's Lee well, we have offset it about 2 miles to the west with our Obar well. We have just fracked that well in the last few days and are completing it. I will say that, that is a Three Forks test whereas the Lee well was a Middle Bakken test.

Stephen Berman – Pritchard Capital Partners

Okay, and then, at some point, I think you guys had some Haynesville acreage, any updates on what you have there and any future plans?

Rick Muncrief

Steve, we have prepared, I believe 5 spacing units for drilling and are making plans to have a rig on that later this year. That’s the status this time, we have them spaced and permits are being applied for this time.

Stephen Berman – Pritchard Capital Partners

And what’s the latest acreage position there, or current acreage position?

Jeff Hume

Well, we have got about, I think about 26,000 acres there, about 2,200 that’s down in the Desoto Parish area, the remainder is up further northeast up in the Cleburne County area or Parish area.

Stephen Berman – Pritchard Capital Partners

Okay, thanks guys.

Jeff Hume

Thank you Steve.

Operator

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

Sven Del Pozzo – C.K. Cooper

Hi, yes, that’s Sven Del Pozzo. Good morning. Yes, just a couple of questions. Was there – did you guys discuss any on what the future development costs were, sorry I am coming in late, for your PV-10 purpose or your PV-10 calculation?

Rick Muncrief

For the PV-10 on the Bakken, we are using $5.4 million per gross well on the North Dakota Bakken. Anadarko Woodford, we are using $5.7 million.

Sven Del Pozzo – C.K. Cooper

Okay. And just at the outset I remember you guys mentioned decrease in the drilling days, about 19-day decrease at 14,000 to 16,000 per day, day rate, you are talking about the North Dakota Bakken, that would save you about $300,000 per well. I am wondering if you increased the frac stages from current 18 to 20 or 22, how much of those or how much incremental CapEx would there be for the more intense competitions?

Rick Muncrief

Yes, the cost savings on those, the days from that we mentioned down to 26 days in our fourth quarter, if you recall, we started the year from being 10-stage fracs and exited the year at 18 to 20 plus stage fracs. So, what we typically use is the cost per stage of about $80,000 to $100,000 per stage, and that’s in essence what has helped us keep the cost down.

Sven Del Pozzo – C.K. Cooper

Okay. And then finally, did you guys mention the net undeveloped acreage number for the North Dakota Bakken at 12/31/09?

Rick Muncrief

Net undeveloped –

Jeff Hume

Yes, net undeveloped pad at 12/31/09 was 387,895.

Sven Del Pozzo – C.K. Cooper

Thank you very much gentlemen.

Jeff Hume

Thank you Sven.

Operator

(Operator instructions) Your next question comes from the line of Jessica Alig with JP Morgan. Please proceed.

Joe Allman – JP Morgan

Hi, this is Joe Allman, good morning everybody.

Jeff Hume

Good morning Joe.

Joe Allman – JP Morgan

In terms of your Cana play, are you still sticking with the 5 to 7 Bcf EURs or do you feel better about increasing that, and could you just talk about the variability across your acreage, you know, if you could separate it, you know, the north, south, east, west, what kind of EURs you are thinking about?

Harold Hamm

Well, you know, it’s really too early to do that, Joe. We are just out drilling our second well offsetting the Brown, it’s about a 5-mile offset, the doors, we are drilling the lateral today, we should have a completion on it here within 35 to 40 days. But it’s going to take some delineation work to really nail that down. At this time, we feel to our CapEx model and cash flow model the 5.7 Bcf model, just or 5.3 Bcf of model just to be on the conservative side. We have got good rates of return with that, you know, with the $5 NYMEX price and $60 oil we are seeing, close to 30% rate of return. We are above those prices, so we have (inaudible) rate of return on that. We think we are going to beat that significantly from, you know, we just have two data points in the 40 miles apart. So, it’s really tough to say what that spread is going to be, but I think you just have to tie it back over and look at what they have had northeast to southeast across the Cana field on as I said earlier, on the distribution of liquids, as you get shallower, you get cooler, less gassy, higher oil content into the south. And so, I think across there, we are going to be probably beat these numbers considerably, but again, we are early in our delineation work of our acreage block and we will know a lot more this fall.

Jack Stark

Joe, I guess that if you look at the total acreage number from Cana and maybe Cana proper what the other operators call it Cana proper, that’s about 43.7 [ph] within that area, and to the northwest, from there to the northwest and including that, I think the number is 124,000 going northwest. Obviously with this Brown well, we feel very good about that acreage extend and up to that area, and hot gas, we drilled a well 5 miles from there now. You know, with the oil component in the south, the southeast acreage, you know, that’s just, we are just going to have to see what that amounts to down there, because it’s a different type of production. You know, we will just have to see as we get a good valid test down there. Our McCalla test was not good. There was mechanical problems you will recall. This Ballard, we haven’t had any problems with it. It has gone very smooth, very well, we feel like this is going to give us a test that we can talk about in next few days. I hope that helps.

Joe Allman – JP Morgan

Yes, it’s very helpful. Thank you. And then moving on to the Bakken, do you have any lease expiration issues where you really need to get on drilling pretty quick and start production as we lose leases?

Harold Hamm

No, Joe, we have actually been pretty aggressively renewing our leases than have identified several key leases that we need to get on drilling for example that area out there around the Guernsey drilled mentioned earlier, it’s one area that we are developing right now that’s has aspiring acreage going out in the first part of this year and we are drilling it right now. Probably about now with our renewal efforts right now, somewhere in the neighborhood of 7% of our undeveloped acreage expires in 2010, we have it identified right now for either renewal or drilling.

Joe Allman – JP Morgan

Okay, that’s helpful. And then lastly, in terms of the ECO-Pad drilling, how many ECO-Pad wells do you plan on drilling this year versus the total?

Rick Muncrief

Well, we plan on having, we are drilling our first one now. We have a second one, which should spud tomorrow. Within the next 45 days I will say, we will have two more pad rigs running and then have the following two by, as Jeff mentioned earlier, by May. So, the total well count is probably about – we don’t have six rigs running for an average of about eight months, it should be around 48 gross wells. We can get a count for that, get back to you on that, Joe, the exact, what’s in the plan from that wells, I just don’t have that off the top of my head.

Joe Allman – JP Morgan

And that’s 48 gross wells out of how many total?

Rick Muncrief

We have a total of –

Jeff Hume

We have 218 in North Dakota.

Joe Allman – JP Morgan

Very helpful. Thank you.

Jeff Hume

Thank you.

Operator

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

Andrew Coleman – UBS

Good morning folks.

Harold Hamm

Hi Andrew.

Andrew Coleman – UBS

Yes, I just wanted to dig in the release a little bit, I am not sure you covered this morning, but can you kind of run down again the PUDs that were, the number of offsets that were booked in, I guess by region, I guess in the Bakken and the Woodford?

Harold Hamm

Sure, our bookings on the start in the North Dakota Bakken, we have got 616 gross wells, 261.9 net wells; and the Montana Bakken, we maintained what we have had, there are not new bookings but what we have is 65 gross, 44.7 net. In the Arkoma, we have 401 gross, 100.3 net wells; and in the Anadarko Woodford, we have 6 gross, 3.5 net wells.

Andrew Coleman – UBS

Okay. And sort of assuming about in places like the Red River, you just kind of just bookings, straight PDP, is this your flat production profile and (inaudible)?

Harold Hamm

Now, there is some PUD production in there. What we have is our performance curve and the area of that curve is above, the current rate is modeled by Ryder Scott as proved undeveloped. We will hit that peak in the next couple of months, and that will be fully booked as proved developed on the Red River Units as far as Cedar Hills by the end of this year. We do have plans to drill some more wells in the Buffalo Units second half of this year, which will probably add some bookings in that area.

Andrew Coleman – UBS

Okay. And then let me just ask it different way then I guess looking at the offset, is it 4 to 1, 5 to 1, for each PDP location or is there something I can get out of the release? You have got the 261, you know, 262 net in the Bakken in the North Dakota side of the Bakken, I guess what’s the number of PDPs that are –

Harold Hamm

The PDPs that we have, well I will have to get that number, I do not have that with – I have got PUD numbers, but not PDP, but we can get that for you. We would be glad to.

Andrew Coleman – UBS

Okay. I will give you guys a shout then after the call.

Harold Hamm

Okay.

Operator

There are no additional questions at this time. I will now like to turn the presentation back over to Mr. Hamm for closing remarks.

Harold Hamm

Thanks everybody. Thanks for bearing with us. There is little noise here in the Oklahoma day. (inaudible) That’s an area, the good thing is they are consuming a lot of jet fuels. So, in summary, we are pleased to have an excellent inventory highway of assets and we are positioned to accelerate growth in production, cash flow and value for our shareholders, as we have seen. As a US independent E&P company, we are focused on our role in developing our company’s domestic energy resources, which have a significant impact on jobs and economies and states where we work.

America’s domestic petroleum industry is today producing 45% of liquid fuels that we consume here in America. We reduced petroleum liquid import to 55% of consumption and it’s our favor, and I thank everybody is aware of the natural gas supply that’s out there today. So, thanks again for joining us today on our earnings call. We will see you next quarter. Thanks.

Operator

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

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

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Continental Resources, Inc. Q4 2009 Earnings Call Transcript
This Transcript
All Transcripts