Continental Resources Q4 2008 Earnings Call Transcript

Transcripts

Continental Resources, Inc. (CLR) Q4 2008 Earnings Call February 26, 2009 10:00 AM ET

Executives

Warren Henry - Vice President of Investor Relations
Harold G. Hamm - Chairman and Chief Executive Officer
John D. Hart - Vice President, Chief Financial Officer and Treasurer
Jeff Hume - Chief Operating Officer

Analysts

Subash Chandra - Jefferies & Co.
David Tameron - Wachovia Capital Markets
Sven Del Pozzo - C.K. Cooper
Leo Mariani - RBC Capital Markets
Stephen Berman - Pritchard Capital
Joseph Allman - JPMorgan
Chris Pikul - Morgan Keegan
Eric Hagen - Banc of America - Merrill Lynch

Operator

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2008 Continental Resources, Inc. Earnings Conference Call. My name is Corrisa and I'll be your coordinator for today. (Operator Instructions).

I would now like to turn the presentation over to your host of today's call, Mr. Warren Henry, Vice President of Investor Relations. Please proceed.

Warren Henry

Thank you, Corrisa. Good morning everyone and welcome to our earnings conference call. On today's call, we will be describing beliefs, goals, expectations, projections, assumptions and guidance that are considered forward-looking statements. Actual results may differ from those contained in our forward-looking statements. For additional information concerning these statements and risks, please refer to the company's filings with the Securities and Exchange Commission.

This morning we published our fourth quarter 2008 earnings press release, which included our revised 2009 capital budget and guidance. Chairman and CEO, Harold Hamm will begin this morning's call with an overview of our growth strategy. Jeff Hume, Chief Operating Officer and Jack Stark, Senior Vice President of Exploration will provide greater detail on developments at our key resource place.

Finally, John Hart, Chief Financial Officer, will discuss balance sheet, management and related issues. After John's comments, we'll be ready for Q&A.

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

Harold G. Hamm

Good morning, everyone and thanks for joining us on this morning's call. We have an interesting mix of information to discuss with you this morning in terms of our key operating programs, we closed our record year in 2008 with a very strong fourth quarter. On the other hand we are cutting back CapEx in 2009 in the phase of low energy prices, focusing on for preserving the integrity of our balance sheet and the value of assets in the ground for better days. We will cover both these topics with you this morning. And then answer your questions about our operating plans for 2009.

First, I would like to review a very strong year just completed. Continental performed at a very high level in 2008, executing our growth plan very well. Net income of 321 million was 74% higher than 2007 after the previous year's results are adjusted pro forma, income taxes as if we've been a subchapter C Corporation throughout 2007.

We generated EBITDAX of 758 million, an increase of 61% over 2007. Production increased 13% as we met our production target for the year 12 million barrels equivalent, despite sharp setbacks in our drilling program from October through December.

Our December 2008 production exit rate of 37,954 barrels oil equivalent was 27% higher than our December 2007. We increased our proved reserves to a 159.3 million barrels oil equivalent, up 18% over 2007.

We participated in 153 net wells in 2008, an increase of 36% over the previous year, and was another company effort. And finally, we increased our undeveloped acreage holdings to more than 1.0 million net acres. We had identified a lot of the attractive resource flows with much of the additional acreage or part in North Dakota, Bakken the largest unconventional oil resource play in lower 48 states as assessed by the USGS.

We do this is in inventories of tremendous platform for growth and the decade that have for Continental. As we noted in our press release, the fourth quarter was also a record quarter, with production increasing 8% over the third quarter of 2008, and almost 19% over the fourth quarter of 2007.

Throughout the escalation in energy prices in 2008, we maintained our operating and fiscal discipline and didn't overleveraged our balance sheet. Although, we increased our operated drill and rig count from 13 in January 2008 to 32 in early October, we maintained flexibility and cumber ourselves with long-term rig contracts.

Finally, we responded decisively last year when the energy pricing environment turned over, hit into breaks on our drilling problem, lying down rigs, and gaining additional liquidity with the banks and our credit facility to can give us more operating flexibility.

Now, while we're proud of our operating accomplishments this past year, we recognize the historic challenges represented by persistent low prices, tight credit and demand destruction related to this recession we're in.

This morning I would like to address investor's concerns about the industry as they may relate to Continental, and the opportunities that we see in this downturn.

First, the integrity of our balance sheet is critical to our ability to grow and create value, and we're mentioned it today to assure a financial strength and operating flexibility.

Our debt increase as we expect in the last five months as we arrested down drilling activity to get operations inline with cash flow. But our current credit debt level remains manageable and debt ratios are very favorable compared to most of our peers. Our financial foundation is very solid. At the same time we have increased our available liquidity by adding new banks to our credit facility and by increasing the level of commitment by banks already in the revolver.

On the spending side, we significantly reduced operating drilling rigs as I mentioned. And we planned to continue laying down rigs to keep CapEx aligned with cash flow if these low prices persist in the future.

We have said that 2009 capital expenditure budget to reflect the reality of current crude oil and natural gas prices. We, Continentals take great pride in our track record of strong growth and while it was clearly prudent in this put the breaks on our growth momentum, this runs against our nature as a company and as an operating team here. But while we believe the current low level of crude commodity prices is sustainable, it makes no sense to force additional supply into depressed pricing market.

Our cost have been is to raining operations, keep debt low and preserve the value of these assets that will have in the ground for more rational market than the days ahead.

I'll be the first to stipulate the last year's $147 peak price was not rationale, but was speculation driven debt bad for the economy, bad for consumers and bad for producers, just due to the economic and other consequences we're dealing with today. But 35 to $40 oil is equally unsustainable and equally damaging if not more so from a long-term perspective. 40% of U.S. drilling rigs have already been laid down. The industry has still dropping about 60 rigs a week, and this will severely limit our ability to meet the nation and world's need for transportation field and other energy resources as the recession bottoms and demand begins to recover.

If history is reliable so the industry will probably overreact on the downside, and we will see another spark in prices, which again will shock consumers and the economy. So at Continental we are dealing with the reality we have here today. We've established valuable acreage position in many of the nations, premier share of resource price where the strength of work through this downturn and to a process recover to levels at more realistically reflect their value.

Finally, we absolutely believe that our gross strategy as a roadmap to long-term and longtime value creation.

As we announced this morning, we've cut 2009 CapEx to 275 million within our budget turbine, fairly the North Dakota outcome will work through Michigan out of these priority plays that we have decided to remain in and remain the most band in 2009.

Crude oil remains our primary focus. We believe it had the strongest chance for crossing rebound as economy, stabilizes fuel demand begins to grow and stops it going down. In the Red River units and Montana, Bakken we'll remain at a maintenance mode, preserving the future opportunity to harvest resource underground when pricing is stronger.

Being a low cost producer and generating superior cash margins remain essential elements of this strategy. Continental continues to rank at or near the top in these categories amongst its peers and we were intend on preserving our ability to perform at a very high level in 2009 and beyond.

Lastly, our gross strategy is in excellent roadmap for value creation, because with a strong balance sheet, solid drilling inventory and efficient operations, we are keeping Continental position for strong, predictable growth in the years ahead. And just our two highest priority plays in North Dakota, Bakken and Arkoma Woodford, we have almost 1,100 potential drilling well locations in our inventory. And if the 3, 4% proves to be separate reservoir a total of potential drilling sides are even higher.

We believe our tremendous inventory will enable us to increase reserves at relatively low risk for many, many years. These oil positions and other resource plays are valuable assets and we are committed to realizing their value to the benefit of our shareholders.

For the other operating detail from our fourth quarter 2008, I refer you to a press release into 10-K which will be filed shortly.

In summary, I believe that Continental team performed at a very high level in a very challenging period in final quarter of 2008. Our mission today is to serve for the rebound and to maximize returns as the market turns back to us.

With that, I'll turn the call over to Jack Hart.

John D. Hart

Thank you, Harold, and good morning everyone. I'll provide an update on the results from our key projects in 2008. And Jeff will follow with an overview of our 2009 revised budget and plans going forward.

We'll start-off with the North Dakota and Montana Bakken place where 2008 proved to be a very successful year for us. We exited the year averaging 11,756 net barrels of oil equivalent for the month of December, an increase of 36% over the same period in 2007. Crude net Reserves also grew 38% over 2007 to 45.7 billion barrels of oil equivalent. Our acreage position increased to 581,000 acres by year-end. And we believe we remain the top leaseholder owner into play. This includes 416,000 net acres in North Dakota and a 165,000 net acres in Montana.

During the year, we completed a 120 gross and 43.4 net wells in the play. This includes 98 gross and 27.2 net wells in North Dakota, and 22 gross and 16.2 net wells in Montana. Our transition to drilling along single laterals and completing these wells with multistage fracture stimulation through uncemented lenders proved to be a critical breakthrough and it provided improved results to rather acreage into play.

Utilizing this technology that 37 gross and 15.9 net completed wells we operated in North Dakota during 2008 at an average initial potential of 597 gross barrels of oil equivalent per day. It is up 68% over the average initial rate of 355 barrels equivalent per day for wells we completed or participated in during 2007.

The estimated gross recover reserves assigned to these wells ranged up to 578,000 barrels of oil equivalent per well and averaged 365,000 gross barrels of oil equivalent per well, which is inline with our North Dakota reserve model of 350 to 400,000 gross recovery barrels of oil equivalent per well.

We also began to use this technology in our Montana Bakken properties in the Omkoli Field, particularly on our 320 acre in-field wells which we began to drill in earnest in 2008. We drilled and completed 12 gross, 10.3 net, 320 acre wells on our properties in the Omkoli Field and the results were right inline with our expected reserve model of 280,000 gross barrels of oil equivalent per well.

In addition to the improved rates and recoveries, we're also starting to see some significant reductions in drilling days per well. Recently, six of our wells drilled over North Dakota reached total debt in 27 to 24 days, which is a 34 to 41% reduction from our historical average. Our North Dakota Bakken drilling team is constantly working to reduce costs as it is working diligently to achieve this in all of our wells.

Our significance is just over a half of the wells we operated in North Dakota during 2008 were drilled in the Three Forks/Sanish reservoir. As you know, we believe the Three Forks/Sanish has the potential to add significant incremental reserves to the Bakken play. To evaluate that potential, we began testing the concept with the interest with the completion of the base 129 each well in May. And during the year we completed or participated in the completion of 27 gross, 10.3 net, Three Forks/Sanish wells and have been pleased with the results. Initial production rates for these wells ranged up to 1,260 gross barrels of oil equivalent per day, and averaged 582 gross barrels of oil equivalent per day.

Gross estimated recovery reserves assigned to the 16 Three Forks/Sanish completions we operated averaged 373,000 barrels of oil equivalent per well, again inline with our reserve model for North Dakota.

These Three Forks/Sanish wells were strategically located throughout our acreage along the Nesson anticline over distance of about a 100 miles north to south, and demonstrate the productive potential of the Three Forks/Sanish reservoir underlying our acreage. In a couple of minutes, Jeff, will discuss plans we have to further test the Three Forks/Sanish in 2009.

In the fourth quarter, we completed our first Montana Three Forks/Sanish test, the Joann 1-32, in we have 89% working interest. This well is located approximately 5 miles north of the Elm Coulee field. Results were disappointing with the well producing an average of 60 barrels of oil equivalent per day during its first nine days on pump. We drilled this well on our 640 acres spacing basis and probably would have had better results had it been drilled on 1,280 acres spacing. But even so, the rock in this particular areas, oil charge and it appears to be very little probability, we continued to evaluate the results here.

In January, we begin our pilot CO2 project to evaluate the potential for enhanced recovery of oil from our Montana Bakken properties in the Elm Coulee field. Utilizing the huff-and-puff technique, we begin injecting CO2 in January and will continue injecting through March. After letting that CO2 soak in for approximately 30 days, the CO2 and associated fluids will be flowed back and analyzed for performance in economics.

Moving on to our Red River Units. During the fourth quarter, the Red River Units averaged 14,058 net barrels of oil equivalent per day, accounting for about 39% of Continental's production in the quarter. This was a 5% increase above our third quarter production and down slightly from the fourth quarter last year.

During the fourth quarter, we have reduced our level of drilling and conversions as we do not feel it makes sense to aggressively accelerate production in the current price environment. This in no way reduces the recoverable reserves from the field. It just decreases the rate in which they are recovered. And Jeff will address this a little bit more in detail shortly.

Our Arkoma Woodford operations also had an outstanding year in 2008. We exited the year with December production averaging 26.4 net million cubic feet of gas per day, which is three times our average of 8.4 million cubic feet of gas per day in December 2007.

Crude reserves grew to 30.7 millions barrels of oil equivalent, an increase of 245% over 2007. For the year, we completed 115 gross, 23.3 net wells that consistent with the combination of exploratory step-up and development drilling. Our drilling department did an excellent job, increasing drilling efficiencies and managed to reduce our average cost per lateral foot drilled in 2008 by 20% over 2007.

With the use of 3D seismic, our geologic team demonstrated that we could identify and navigate wellbores across large fields enabled us to cost effectively develop acreage where we have folks transversing those properties.

In 2008, drilling results expanded the scope of non-production to the western extent of our Ashland AMI, south into our big man prospect, and we also completed our first well in deep Eastern McAlister area.

Our significance, we another operational play demonstrated the 80 acre spacing is economic which supports the potential we see a 1.3 tcf of unrisked reserves on our 47,000 net acres based on an 80 acre basis. To complete wells on 80 acres spacing, we began to simul-frac wells to more effectively stimulate and produce the Woodford Shale while causing minimal disruption to the existing production and adjacent wells.

During the fourth quarter of 2008 we completed the Pasquali, the Luna-Pratt and the Wilson simul-fracs in the Ashland AMI. The seven Pasquali wells flowed at an average rate of 2.4 million cubic feet of gas per day, with the best well flowing at about 3.6 million a day.

The Luna-Pratt wells flowed at an average gross initial rate of 3.8 million cubic feet of gas per day, with the best well flowing at a rate of 4.6 gross million cubic feet of gas per day. And the two Wilson wells flowed at an average gross initial rate of 7.2 million cubic feet of gas per day, with the best well flowing at 8.5 million cubic feet. So, very nice completions there.

Move on to our emerging place, and particularly, go into the Woodford of the Anadarko Basin, and we're currently controlling 117,000 net acres in the Canadian, Grady, Blaine Custer and Dewey Counties, a long trend and adjacent to ongoing drilling activity in the play.

We are just getting started in the play from a drilling standpoint but recent announcements by experienced operators active in the play are encouraging with the initial production rates of up to 8.3 million cubic feet of gas a day and reserves estimated upwards of 9 Bcf. At this time, we are in the process of completing our first two wells near the Brown 1-2, in which we have a 100% working interest and the McCalla 1-11H, in which we have about 90% working interest.

We also control about 28,000 net acres in the emerging Atoka shale play, which is also in the Anadarko Basin of Western Oklahoma and our Texas Panhandle. This acreage is located primarily at Ellis County and Richland County, Texas.

Public record shows that 37 horizontal Atoka wells have been completed by energy repairs with initial rates up to 7.5 million cubic feet of gas per day.

During the fourth quarter of 2008, we drilled two horizontal Atoka test. The first, the Shrewder 1-22 in which we had a 100% working interest is located in Ellis County. Oklahoma completed flowing 1.3 million cubic feet of gas today from a short 1,300 foot lateral that was treated with just three stage fracs.

The Joann Trust 1-68H in which we had 100% working as well at Richland County was recently completed as well, and is in early stages of testing and was following at about 700 Mcf a day at this time.

Moving now to Michigan. In the Hillsdale County, a Michigan Trenton-Black River play we currently have 6 gross, 4.9 net operating wells producing, 562 barrels a day gross, 465 net. And three of these wells are capable of flowing in excess of 200 barrels per day, as liable set by the Michigan department of the environmental quality and three are restricted by natural gas length restrictions that will be removed once these wells are connected to natural gas pipeline.

And natural gas gathering pipeline has been installed and processing facilities are under construction to enable these player restricted wells to produce to the 200 barrel a day allowable rate.

We own approximately 52,000 net acres in the play. And during 2008, we acquired an additional 20 square miles of 3D seismic on our Chicago/Norad project. Interpretation of the seismic data, identified up to 14 potential drilling allocations of which four are permitted at this time. We planned to acquire another 6.5 square miles of additional 3D data in 2009 to continue to build our inventory.

And I'll close with just a couple of conventional completions of note down on Nacogdoches County, Texas. We completed the number one, in which we have 75% working interest. The well was flowing initially at a rate of 4.4 million cubic feet of gas and 50 barrels of oil equivalent day from lower free oil sands.

And then going back up into regional County Montana, we completed the Fret 1-16 in which we had 89% working interest. And it was completed flowing or producing 286 barrels of oil equivalent day from the seismic that find Red River porosities out. So another nice completion there.

With that, I'll turn the call over to Jeff to discuss our 2009 CapEx and operating plans.

Jeff Hume

Thank you, Jack. As you saw in this morning's press release, a 128 million or 61% of our 2009 drilling related CapEx is allocated to North Dakota Bakken and North Arkoma Woodford place, and we expect these to account for three quarters of our net wells this year.

The next largest portion of our CapEx would be 46 million in the continued investment of the secondary recovery operations in the Red River units. Minimal amounts of drilling work over and facilities CapEx we spent in other place, while energy commodity prices remain low.

We have 72 million in 2009 CapEx budgeted to drill 86 gross wells, 20.2 net in the North Dakota Bakken play during 2009. This reflects a significant reduction in both operated and non operated recount for the year in response to today's low commodity prices. We have also budgeted 32 million for leasing to maintain a strategically augment our acreage in key segments of the play.

2009 drilling will focus on underdeveloped North Dakota acreage, primarily along the Nesson anticline where we expect to achieve consistent results inline with our expectations of 350 to 400 gross Mboe per well. We will also begin exploratory drilling on our Ronholdt project in Mercer County in North Dakota, where we are targeting in Middle Bakken dolomite shoreline trend analogies to the Elm Coulee field along the southeast plank of the basin.

One of the most notable events we look forward to this year would be the drilling in midsummer of the first Middle Bakken well with the lateral selection stacked over one of our earliest Three Forks/Sanish wells. We plan to drill a companion well to the Mathistad 1-35H in McKenzie County, landing the lateral approximately 75 feet above the Three Forks/Sanish zone in the Middle Bakken layer, the stack lateral from the separate well, vertical wellbore.

Production performance of this new Mathistad little Bakken well and its effect on the original Three Forks/Sanish well will provide valuable additional information on productivity of the two formations in whether they appeared to be separate reservoirs.

However, we're very pleased with the success for 320 acre infield drilling program in Elm Coulee field in Richmond County, Montana during 2008. We have elected to differ drilling of any of the 57 or remaining 320 acre infield locations until prices improved.

Now let's move on to the Red River Units. Under the revised 2009 capital expenditure budget, we will spend 46 million in the units with plans to drill 4 producer wells, 2 disposal wells, 6 water supply well and conversion of producing an air injection wells to water injectors.

As we noted in the press release, we have suspended further acceleration of the secondary recovery project in units to preserve that resource for higher priced environment. Please note that this... that we are not doing anything to jeopardize ultimate recovery of reserves in this asset. This change of plan maximizes the rate of return under the current commodity prices. Production in the units is expected to decline in the first quarter of 2009 due to the conversion of producer wells to injectors.

In the second and third quarters, production will be approximately equal to year-end 2008 level and then accelerate through the fourth quarter of 2009 and into 2010. We expect production to peak at just over 17,000 barrels oil equivalent per day in units in mid-2010.

In our Arkoma base, Arkoma Woodford acreage in Southeast Oklahoma, we expect to spend 56 million, drilling 63 gross and 8 net wells during 2009. We have also budgeted 7.3 million for releasing to maintain in lower acreage. As with the Bakken, this budget reflects significant reduction in both operating and non-operated rig count for the year. We currently have one operated rig drilling in the play, compared to six rigs beginning in the fourth quarter.

In our emerging plays, we have allocated $23 million to 18 gross to five net wells starting the emerging shale and conventional plays in the Anadarko Basin. We have also budgeted $6.3 million in land seismic. Some of these revised CapEx allocation should yield productions for the year of 12.5 to 13 million barrels per oil equivalent. So year-over-year growth of up to 8%. Most of our growth is expected to be in the North Dakota Bakken and Arkoma Woodford plays which grows from the Red River Units, starting back up in the fourth quarter and continuing into 2010.

This growth outlook is clearly below our capabilities, and simply a reflection of scale back CapEx in an unfavorable pricing market. We believe the value of our assets will be best realized by slowing down our production growth rate until the economic downturn show signs of bottoming and demand begins to recover.

Now, I'd like to turn the call over to John Hart, our Chief Financial Officer. John.

John D. Hart

Thank you, Jeff. I'd like to provide some additional color on our balance sheet and our credit facility before we open the call to questions.

As Harold noted, 2008 was a strong year with significant earnings, production and reserves growth. Albeit our earnings were negatively impacted by low commodity prices in the fourth quarter, we believe the strong growth in our operations is indicative of the underlying strength of our assets, positioning us to capitalize on the ultimate recovery of commodity prices.

We ended the strong 2008 with slightly in excess of 5 million in cash and 376 million in long-term debt. Since year-end 2008, debt has increased to a current level of 474 million. This was expected.

Given the lag in bringing down CapEx, even though we started that process aggressively in the fourth quarter. The two primary timing factors are outstanding drilling and related invoices that have to work their way through the system to be partially reduced by collection of joint interest receivables and secondly the process of the billing, contractual drilling commitments on operated rigs prior to laying them down.

Of our current total of seven operated drilling rigs, only two have contractual terms beyond May 2009. So we can continue to lay down rigs and cut activity with current low price levels persist through the spring.

Now despite this reduction in rigs, we still have good production growth momentum, stemming from the overhang effect of completions completed late in 2008 or early in 2009. Over the next several months, we expect debt levels to increase a bit more before we begin managing debt back down in the second half of 2009 as the bulk of our rig commitments lapsed.

We have ample liquidity in the meantime. We have revised our 2009 CapEx budget to bring it inline with our cash flow outlook for the year. Additionally, we have been very successful in the past few months, increasing credit facility commitments and bringing strong new banks into our revolving credit facility.

Our intent was to assure that we have operating flexibility to gear down our drilling program in a rational deliberate manner, and at the same time provide additional dry powder as the downturn plays out.

From December 2008 through to-date, we have increased our commitment level in our facility by 273 million to the current level of 673 million. We believe that should we choose, we would be able to increase our commitments to a higher amount than where they currently stand. The new demand on our facility is 750 million. In the process of gaining additional borrowing capacity, we increased the number of banks in our facility from 10 to 14 and six of the original 10 banks increased their commitment levels.

Given the recent state of the credit markets, we were very gratified at this vote of confidence in our balance sheet, operating strategy and asset-based and premier shale resource plays. We now have a large diverse group of banks in our credit facility, and we believe the higher commitment level provides valuable flexibility since strategic opportunities arises the downturn runs its course.

With that, I would like to turn it over for questions-and-answers.

Question-and-Answer Session

Operator

(Operator Instructions). And your first question comes from the line of Subash Chandra of Jefferies. Please proceed.

Subash Chandra - Jefferies & Co.

Yeah. Hi, good morning everyone. Quick question, first on just the... for more detail on the reserves. Maybe it was in there, I apologize if I missed it. But what was the Bakken split in '08 between Montana and North Dakota, the reverse split, sorry.

Harold Hamm

Are you telling that, are you telling about year-end reserves?

Subash Chandra - Jefferies & Co.

Yeah, year-end reserves. I thought I read just a comprehensive number. I'm not sure if I saw the spilt between the two states.

Jeff Hume

Okay. The Montana Bakken was 27.1 million barrels and the North Dakota Bakken was 17.4 million of barrels.

Subash Chandra - Jefferies & Co.

Thank you. So could you maybe go into some more detail on the spud booking. Was this pretty much going to 80s on big part of your acreage or maybe some more detail on, if 80s is now sort of have been fully booked in the field?

Jeff Hume

We went... in the Arkoma Woodford, we put a small portion of our 648 acre tracks down to 80s, but very conservative amount of those. And in the North Dakota Bakken, we pretty well staying on the 1,280 spacing and owned offsets on drill well offsets. So any offsets parallel to the original wellbore only. So we have not brought that down to increased density on 640 acre spacing near the storage reserve bookings Subash.

Subash Chandra - Jefferies & Co.

Okay. And so what was the type of threshold for the Oklahoma down spacing, sort of I'm looking at the '09 it looks kind of like $7 million a well. I'm just doing some very simple math. I imagine there is some facilities, other charges in there, but looks like $7 million a well. What type of IP should we be looking at to sort of say, Hey, this is in say $5, $6 gas environment, realized gas environment. This is what part of the field could be down space.

Jeff Hume

Well, that 7 million that you are seeing is due to some carryout at the end and not having completions. The actual development cost is less than that Subash. We're getting our costs down in the... on the operated well which are about two-thirds of the wells, net wells being drilled and are going to be in the 4.5 million to 5 million range. We feel like we'll get that down some more. The initial IP is going to be running 3 to 4 Mcf per day and getting 3 to 4 Bcf per well gross on those type of wells.

Subash Chandra - Jefferies & Co.

Okay. Got you. And when you look at sort of the leading edge wells, something like a, maybe some of these results you've seen, but not Pasquali, I am sorry, Wilson so on and so forth. What is sort of the price threshold you think you need to see realize to earn a competitive return out there say 20% type return?

Jeff Hume

I would say 4 to $5 at the wellhead or above would give us a very good return.

Subash Chandra - Jefferies & Co.

Okay, okay. And if I just stop over to Three Forks. XTO at their Analyst Meeting talked about 7 million barrels of oil in plays, I know and maybe this is not the ideal way to look at Three Forks potential. But do you have an estimate of what it might be?

Jeff Hume

Of oil in place, I really don't... in the past we on a volumetric analysis, we've been on a 1,280 of total reservoir of 10 to 12. So that's somewhat inline with what you're hearing from the other operators of Seven Forks is to Three Forks, being it's roughly 50% of the resource base and that's what we hope to prove with our Mathistad wellbore this summer.

Subash Chandra - Jefferies & Co.

And then one last question on Three Forks. You've now definitely concluded that it is that you are draining a distinct reservoir when you make those wells, make those completions or is that something that still needs to be tested?

Jeff Hume

It still needs to be tested and that's the reason for the Mathistad test that we mentioned in the commentary to provide that. The only information we have at this time is reservoir simulation work which indicates that it is separate reservoirs. But that, so in the laboratory and the science shows that it's separate. Now, we have to go out in the field and prove it, and that's the Mathistad will be our first step in accomplishing that.

Subash Chandra - Jefferies & Co.

Great. Thank you very much.

Jeff Hume

Thank you.

Operator

And your next question comes from the line of David Tameron of Wachovia. Please proceed.

David Tameron - Wachovia Capital Markets

Hi. My question just got answered. Thank you.

Operator

And your next question comes from the line of John Freeman of Continental (ph). Please proceed.

Unidentified Analyst

Good morning, guys.

Jeff Hume

Hello, John.

Unidentified Analyst

Just want to make sure that I got one number right, the North Dakota Bakken average EUR was 365,000 barrels, is that right?

Jeff Hume

Yes, that's correct John.

Unidentified Analyst

So I'm just trying to reconcile, I understand you're not really changing the 400,000 barrel EUR guidance in the play. But I'm just looking at last year, seven day average Bakken was 319 barrels a day and they got booked at about 335,000 barrel EUR. And so generally we've taken a seven day rate tons of 1000, that's in the ballpark of what the EURs are being. And so I'm looking at '08 and the average seven day IP rate was in excess of 500 barrels a day. So I'm curious why the EUR wouldn't end up being closer to 500?

Jeff Hume

I think, that's conservatism of the Ryder Scott forecasters. And the numbers that we are giving you on reserves are booked reserves as Ryder Scott presented those. And John, you'll realize a lot of these wells are still in the flowing stage. And they are limited by putting the decline curve on the actual production as we put these wells on pump, which run a lot of these Three Forks wells, for instance, the Mathistad we just put on pump this past week, it was completed last April. They have an uptick and we'll change that curve.

Internally, we'd see reserves in excess of 400,000 barrels for those wells. But we... as I have said many times, we report only book reserves by Ryder Scott. So we're using their conservatism in our modeling.

Unidentified Analyst

Okay, that helps. And then on the Three Forks/Sanish, if I basically throw out anything that was done up and divide in Burke County, the rates are kind of close to about a 1,000 barrels a day. And I know this is still early but, at least on a decline curve it looks identical that what you are seeing on the Middle Bakken?

Jeff Hume

Not really. We're seeing a little bit in the North Syria, up to the north and in the Divide County we're seeing a flatter curve not as steep. Our IPs were not as high and part of that is just barrel depth, it's not as deep in the initial bottom whole pressures, not as high as we have down in the McKenzie, Dunn County area. That gives us a little bit lower IP, but we have a little slightly higher perm there as we're getting a slightly flatter curve up there.

We also have a bit of higher water saturation that helps flat cause that curve flat now. The... we do have few wells up in the north that have very high IPs or El Mar (ph) up there had excess of 1,000 barrels a day, very strong well, in fact one of the stronger wells we have. So again it's local fracturing, micro-fracturing what you have. We still got wells spread out over very large area of our acreage. As we drill additional wells and increase those we expect to see our recoveries improve as we drill more and more wells in the sweeter areas.

Unidentified Analyst

Okay. And then moving on to the differentials in the Williston, I know XTO the other day said they have already seen the differential growth from about $15 in December down to 4 to $5 currently. Are you all seeing the same thing and what's kind of your outlook for differentials going forward?

Harold Hamm

Yeah, John this is Harold. We, for instance, just look at currency while only market net that market point not at the well here. For instance, December we saw a minus 16.25 for December and for March we've seen a minus $4. So about a $12.25 correction just in a period of time.

Unidentified Analyst

Great. And then just last question and I'll turn over to somebody else. On the completed well costs we've been using 5.8 million in the North Dakota Bakken. Just given how much rig rate to come down and then steel costs, what's kind of your guidance now on cost in the Bakken?

Jeff Hume

Right now our average cost is probably around 5.5 million and that's still with a 14 stage frac. We've... so with that and John we haven't done any work yet on reducing steel cost or rig cost because we're still working under primary drilling rig contract terms and we're still working the inventory that we had committed to on steel. We'll be through working that inventory by about end of this first quarter. And we expect to see further cost reductions on those AFEs through the year.

We feel at this time we have achieved about a 15% reduction in the costs we experienced at the peak last summer. We feel like we can cut that down to a total savings over that peak rate of 30 to 40% as we renewed the rig contracts and renew steel pricing.

Unidentified Analyst

Great, thanks. That's all I had. Thanks guys.

Jeff Hume

Welcome.

Operator

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

Sven Del Pozzo - C.K. Cooper

Hey, good morning gentlemen. It's Sven Del Pozzo. I'd like to know a little bit more about the logistics to get oil from your producing areas to market in particular, I was looking at the progression of the White Cliffs pipeline completion. And, in general, how that might help differentials, or helping now differentials for all producers or at least, if that might keep them more, I understand that they narrowed more recently. But over the longer term, whether that will help reduce volatility in widening and narrowing the basis differential and if that makes sense that White Cliffs completion will help. And also, how you would get, or how any operator would get the oil from the end of the view pipeline to the beginning of the White Cliffs' pipeline from currency to flat bill?

Jeff Hume

Sven that's very good question. The White Cliffs are scheduled to start in May at this time. They keep pushing it back. But in May there was a 70 mile, the line that jumps from Cushing and ends at Platteville, Colorado, there is a 70 mile piece of pipe that was already designed, laid out and they were buying right away when SimPro went into bankruptcy. That piece of pipe will be put in fairly quickly once the line is up. There is already adequate pipe from the currency market to Cheyenne, Wyoming.

So we'll see I think by the end of the year the ability to move oil out of the Currency market. That should effectively increase the takeaway capacity of up 240,000 barrels a day out of the currency market directly to Cushing which will stabilize pricing there. So that currency market will have takeaway capacity directly into Cushing, directly into Wood River, Illinois though the flat pipeline and into the Salt Lake City, Cheyenne and Denver market. So it will increase takeaway capacity and that always helps in the differential of that that marketing point.

Sven Del Pozzo - C.K. Cooper

Okay. And so its not just Bakken oil that would make it's way into these pipes, but are there other computing sources of oil that tend to cause a periodic widening of your basis differentials in North Dakota?

Jeff Hume

Well, the various oils that go into the currency market all of Wyoming production oil. The express pipeline coming out of Canada comes through there, with Canadian crude and then the Williston market. When you get down to flat there you have the DJ Basin market. That line was designed to take about 20,000 to 25000 barrels a day out of that market that is currently competing with those barrels at Denver. So that will take some of that out of the market also.

Sven Del Pozzo - C.K. Cooper

Well, thank you. And my second question, regard to the ongoing negotiations with, I mean it's more of a qualitative question I guess. The negotiations with your vendors and service companies in the Bakken in order to get service cost down, I mean how reticent are they and are they coming around to the economic realities in the region?

Jeff Hume

Sven, they are moving very rapidly as we... most of the vendors are lowering prices as fast as they can. You've got to realize they've go cost drivers and commitments on their end too and as they work those out, they have been very responsive to reducing price. They realize that for all of this to survive in this climate, we have to get cost down. So we're seeing that the cost come down very rapidly. We are working on not only cost reductions through the vendors, but also as we mentioned, we're working very hard on this pure performance out there.

As the industry shrinks rig count wise, the experience, talent starts coming back into a higher density on the well. You get just a little better performance from more experienced people on the well who're seeing as Jack pointed out several completions in North Dakota now at these wells are drilling time down to sub 27 days. From our AFP right now is around 39 day well. So if we can get a sustained say 30 day well, it will take 25% of the rig and associated services off and that's in addition to results we'll get from vendors.

But that's an ongoing process of both vendors and performers. That is the opportunity through a downturn for everyone. It's difficult for everyone, but it is going on and most... all the vendors are very responsive to the need.

Sven Del Pozzo - C.K. Cooper

Okay. And lastly, I was curious about the more energy intensive operations in Red River Units, with water floods I was thinking with energy cost coming down, the cost would decline substantially there. Is there anyway you can give me an indication of how much production costs have declined in your more energy intensive operations there?

Jeff Hume

Most of our lifting cost is tied. Our biggest cost driver is electricity, and then the second largest is natural gas, because we do have some natural gas fire compression up there. The electricity portion is longer term contracts, but very favorable contracts. We won't see that portion of the lifting cost reduced. However, the natural gas portion of any coupled of air injection units, Medicine Pole Hills for instance is entirely fired by natural gas. Those prices are a third of what they where a year ago. So, that portion of lifting cost is going to be reduced.

We are seeing some reduction in chemicals and some associated service such as service rigs and also in materials, we are seeing circle rod prices and tubing being reduced, some of our maintenance equipment being reduced at this time also.

Sven Del Pozzo - C.K. Cooper

Alright. Thank you very much.

Unidentified Analyst

Thank you.

Operator

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

Leo Mariani - RBC Capital Markets

Yeah. Good morning guys.

Jeff Hume

Good morning, Leo.

Unidentified Analyst

Hello.

Leo Mariani - RBC Capital Markets

Couple of quick questions here for you. You got the seven operator rigs running right now. You guys are talking about some of those rigs turning to rollout contract in the next several months. Just trying to get a sense of where you would look to drop rigs if prices stay very low here in the (inaudible).

Jeff Hume

Well, yeah, where we have these rig commitments are up in the North Dakota Bakken and the are Arkoma. And so those are places that, should prices that you say, continue to stay depressed we have the ability to release those rigs and keep our cost under control. So we should see those, as John had said, most of those roll off here in May with just one contract going on through 2011.

Leo Mariani - RBC Capital Markets

Okay.

John Hart

I might there that our rig contract prices were never as high as some of those you saw with other operators out there.

Leo Mariani - RBC Capital Markets

Okay. In terms of the North Dakota Bakken pay, obviously bigger upside for you guys, what type of crude price are you looking at to really start to increase activity out there?

John Hart

What we are seeing on crude price to really start accelerating again, I think when we see crude oil go above $60 we'll really take off as when the play economics really start to take off again. In the current strip, we're probably in that 8 to 10% rate of return. At current cost as we get cost down that will improve probably to a point or two might get up to 11 or 12%. But we really need to see that price move on up into 60 and above and which we think will occur in the second half of the year. If that does occur, we'll start seeing rates of return in excess of 15% allowed acceleration.

Leo Mariani - RBC Capital Markets

Okay, question on Michigan here, is there activity planned in 2009? I guess my understanding is that play which you had several wells that were fairly restricted of that 200 barrel a day level, that were capable of producing more. And you folks are going to go and lobby the Michigan oil and gas mission to get some of the discretionary (ph). Curious if there's any update on that process and what your potential activity levels would be going forward?

Harold Hamm

As Jeff said we had two issues up there. One was flaring blue (ph). As long as we have gas flaring, that's an issue and it refrains production. We do have gathering system and that has been connected. And the process equipment is being put in place right now. So that should be -- at least one of those restrictions right there and that will happen within probably next 30, 40 days. That's what we are expecting.

So once that occurs we'll come up to a level on those wells. We have four permitted. We have no plans to drill at this time as discretionary with us. We do have rigs and equipment available should we want to go forward. And of course we'll wait after the growth dollars and everything are -- perhaps last up to spring, probably before we go forward.

Unidentified Analyst

And even if we like to defer some of this drilling as Harold mentioned there in this year, we still see some production growth there. Once we get the pipeline connected and the gas plant in place, we'll actually see the wells that aren't stable at this point due to flaring which takes some to get up to the 200 barrel level, we'll see those. To be able to get there, we should sure to increase production in the project.

Leo Mariani - RBC Capital Markets

Okay. Is there any pending decision or anything up in Michigan to allow some of those wells to produce 1, 200 barrels a day or is that restriction still in place, are you guys talking to the Oil and Gas Commission about that at all?

Harold Hamm

We continue that discussion with them and right now we have not had relief from that yet.

Leo Mariani - RBC Capital Markets

Okay. Thanks for your time.

Harold Hamm

You bet.

Operator

And your next question comes from the line of Steve Berman of Pritchard Capital. Please proceed.

Stephen Berman - Pritchard Capital

Good morning gentlemen. Can I start with the same kind of questioning on differentials as they're impacting Arkoma Woodford including both historical and what you seeing going forward and maybe talk about some of the pipelines coming into the Mid-continent that should be helping there?

Harold Hamm

Yeah Steve we are seeing the slowdown within that field of course. We talked to add about 50 rigs and now I think we are down 36, so that's taken a -- that's given lot of relief over there as far as pipeline needs going forward. So right now we can get our gas to market fairly easily. We are not seeing a huge difference over there. I think it's been running close to a $1, is about we said or something less than a dollar. So we have... I guess a slowdown on instance to some plants but another it allows pipeline infrastructure to be built to put in place in those going forward. So it is leased up to --

Stephen Berman - Pritchard Capital

And moving to the west of the Anadarko Woodford I mean that the two test wells you're drilling there, I mean are you just taking your time for the science or you intentionally maybe even slow completions to try and bring some costs down? Or can you just elaborate because I mean Devon and Maersk have had some terrific results on these plays, exciting a lot of people. So I was just wondering if you could put a little more color on what you think over there.

Jeff Hume

Sure, Steve. We are putting quite a bit of science into these wells. They are step-out, so good distance away from where the current activity is, however the rocks look almost exactly the same, petro-physical analysis from well logs. Our first well has been fraced. We currently have bottom hole pressure instruments in the well looking at trying to get some science on the rock and to pressure how it's functioning.

Together the second well which is in Ellis County, Oklahoma is preparing to be fraced, I believe it is scheduled for about two weeks out. 2 to 3 weeks out we'll be fracing that. So again, there once we get it, the low bed will occupy also there is some pressure information on that. It's just kind of a process you go through and you drill wells that long or step out, you just have to get the science as you go. So it is slower than normal slower that we would like.

Harold Hamm

I must say that, we were in those original wells, with Devons, we have lot of information coming out there and that has something we call core area. We see that much is the lack of (inaudible) there?

Stephen Berman - Pritchard Capital

And it is not having an operated rig going now beyond the two test wells is just function of low gas prices and high differentials?

Unidentified Analyst

Well it's just matter of convince yourself self that you ought to be drilling any wells out there at these costs today.

Stephen Berman - Pritchard Capital

And then in terms of overall activity are you drilling any wells and not completing them to try and bring the costs down? Are you like for example EOG just shutting some wells in the Bakken. Are you doing that in any place actually shutting in wells and in any of your place right now?

Unidentified Analyst

No, we have not shut any wells, and Steve we have on the other hand on completions we haven't delayed any or postponed any. But we have not put as big a push on getting them completed quickly. We're trying to work with the vendors to get their crews ample rest between time minimize overtime hours and that type of things, schedule completion work as you realize the 14 stage fracs in the North Dakota Bakken and nine stage fracs in Arkoma Woodford, do take a lot of man-hours when you are doing that and service comes to try and to minimize their cost to get, their cost may down. So we are working with them on that which stretches it out a little bit longer than normal but nothing to a great extent, we don't have wells, being drilled and shut in at this time.

Stephen Berman - Pritchard Capital

And one question on the bank facility. Can you go up to the facility size of 750 just to refresh my memory, on your own or does that need to be agreed to by everybody?

Unidentified Analyst

Yes you have to obtain commitments from banks to do that but within our bank group including the newer banks that we have added, we have a number that can continue to step up to the larger commitments and they have expressed interest in doing that. We've also been a very successful over the last since the end of December through now in adding additional banks, growing the facility size bank number wise but about 40% ordinary banks. And then so we believe that within existing banks or adding additional ones outside that we could grow it further if we so choose.

Stephen Berman - Pritchard Capital

And when would be the next, call it re-determination date?

Unidentified Analyst

Our re-determination is in April as with most of the industry. That is coming up but at the bank's current prospects, I would -- our stress test, not very comfortable and our ability to draw to the 750 if we so choose.

Stephen Berman - Pritchard Capital

Thank you.

Harold Hamm

Thank you.

Operator

Your next question comes from the line of Joe Allman of JPMorgan. Please proceed.

Joseph Allman - JPMorgan

Thank you. Good morning everybody.

Harold Hamm

Good morning Joe.

Joseph Allman - JPMorgan

Just another question on the differential in the Bakken. So, when I look at your guidance for '09 in the oil differentials of 8 to $10 and we're now looking at around $4 at the currency market. Can you just, what is your outlook actually... would you expect that the differentials will widen and why would that be and just reconcile the current differentials with your 8 to $10 guidance?

Harold Hamm

We don't expect them to widen. It's kind of unique up there write-down with clear Brooke actually being a larger differential than currency, about a couple of dollars over there. So March, we're seeing that number is 673, so at the well, so that's kind of where we see it. We don't see them widening at this point. The differentials kind of result of being able to move the oil and half capacities and all that kind business in and it has gotten somewhat better with the 40% reduction rates up there.

Joseph Allman - JPMorgan

So is the 8 to $10 guidance you are giving, would you just consider that conservative?

Jeff Hume

No, I think Joe what you're going to see for the year average, I think we need to stay with that 8 to 10 and the reason is on the off season in the fall. The fourth quarter, we have seen repeated higher differentials in the non-dazzling market months, and then it narrows like right now as Harold was relaying to you with bad debt has come back very rapidly from December to -- we're looking at well ahead at $7 range on the Bakken now a little higher than that on the Red River barrels. But I think for the overall year we're going to be at that 8 to $10 window when you average everything out and this is just the cycles we go through.

Joseph Allman - JPMorgan

Okay, that's helpful. I guess and just looking back at '08 capital spending, could you break out what the E&D spending was versus the leasehold spending?

Jeff Hume

We will try to grab you a number.

Harold Hamm

We've got I think this will be right her, John. It's 676

John Hart

For E&D.

Harold Hamm

And leasing brokerage et cetera was 206.

Joseph Allman - JPMorgan

Okay, that's helpful. And then lastly, on your negative reservations 13.3 million barrels, what's the breakout there of true developers as spuds?

Harold Hamm

We will have to get back for you Joe.

Joseph Allman - JPMorgan

Okay, I appreciate it. All right, thanks everybody.

Harold Hamm

Thank you, Joe.

Operator

And your next question comes from the line of Chris Pikul of Morgan Keegan. Please proceed.