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Executives

Harold Hamm - Executive Chairman, Chief Executive Officer, Member of Nominating/Corporate Governance Committee and Member of Compensation Committee

John D. Hart - Chief Financial Officer, Principal Accounting Officer, Senior Vice President and Treasurer

Jack H. Stark - Senior Vice President of Exploration

Jeffery B. Hume - President and Chief Operating Officer

Analysts

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Mike Jones - Imperial Capital, LLC, Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Subash Chandra - Jefferies & Company, Inc., Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Scott M. Wilmoth - Simmons & Company International, Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

Unknown Analyst -

Continental Resources (CLR) Q3 2011 Earnings Call November 3, 2011 10:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Continental Resources Third Quarter 2011 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, and then we will have a question-and-answer period. Other members of management are available to answer your questions.

Now I will turn the call over to Mr. Hamm. Please go ahead.

Harold Hamm

Welcome everyone to the third quarter earnings call. In St. Louis Cardinals' fashion, Continental's earnings have rebounded from weather dampened but positive first and second quarter earnings to record production level growth of 23% quarter-over-quarter and profit levels of net income $439.1 million for the quarter.

Our report this morning will give you a glimpse of the longer-term development profile of Continental's position in the Bakken that we've discussed previously on our calls. Not only for our 5-year plan set for 2009 through '14, but beyond. Our next call, in late February, we will announce our 5-year plan beginning 2012 through '16.

Jeff Hume and John Hart joins me this morning to provide quarterly details, as well as the rest of our team is here for Q&A, and I'll come back on to give you my views to the recovering Cushing market and the second bench impact of the Three Forks proven production of our Charlotte well prior to Q&A.

So with that, I'll turn the call over to Jeff.

Jeffery B. Hume

Thank you, Harold. Continental's third quarter was all about production growth. Production increased to 66,289 barrels oil equivalent per day, a 23% increase over the second quarter of 2011. This tremendous achievement was a result of our team's efforts company-wide in addition to continued strong growth in the Bakken.

We are also really pleased to report that our Charlotte 2-22H, which targeted the second bench of the Three Forks's formation, proved successful and tested 1,140 barrels of oil equivalent per day at 1,650 pounds per square inch on a 26/64" choke. What is significant about this test is that it indicates there could be incremental reserves to be harvested deeper in the Three Forks formation. Continental has been a pioneer in developing the Three Forks formation, starting in 2008 with it's Bice 1-29 and Mathistad 135 wells in Dunn and McKenzie counties.

Since that time, hundreds of Three Forks wells have been drilled by Continental and others, targeting the upper part of the Three Forks formation, approximately 20 feet below the base of the lower Bakken Shale. As you may recall from our second quarter call, Continental elected to do some additional science this year to evaluate the entire Three Forks formation, which reaches up to 270 feet in thickness in portions of the Williston Basin.

During the year, we acquired 6 cores of the entire Three Forks formation underlying our acreage and found that there are up to 4 benches of oil-bearing dolomite within the Three Forks. We refer to them as the first, second, third and fourth benches.

Dolomite development in each bench varied, with the first and second benches at the top being the most uniform and widespread and the third and fourth benches being developed on a more localized basis. The cores were located along a 115-mile stretch across our acreage north to south. Encouraged by the cores, we elected to drill the Charlotte 2-22 to test the commerciality of the second bench. The Charlotte was drilled and completed in the second bench, approximately 50 feet below the location of a typical first bench well. So we have demonstrated the commerciality of the second bench.

Now let's talk about the production growth in the third quarter. The Bakken played the lead role with production increasing to 34,505 barrels of oil equivalent per day in the third quarter, up 27% from the second quarter this year. Production also increased in Oklahoma Woodford, most notably in the Anadarko portion of the play where we have 14 rigs operating today. Anadarko Woodford volumes were 78% higher in the third quarter compared to the second quarter of 2011.

Finally, I'm really proud to note that third quarter production in the Red River Units increased 4% to 14,954 barrels of oil equivalent per day. Those of you who have followed Continental for some time may remember me stating a couple of years ago that at about this time, we expect the production units to be trending down. Apparently, our Units Team was busy working, didn't listen to the call, because not only have they maintained production, they've increased it.

This is due to the combination of factors. In the Cedar Hills units, we have repositioned high-volume downhole pumps to optimize production rates and have continued to drill new wells and convert producing wells to injector wells. In the Buffalo and Medicine Pole Hill units, we've increased our air injection capacity with additional compression, which in turn has generated stronger production. So overall, the Units Team has done a tremendous job of maintaining and increasing production.

Beyond our production growth, in the third quarter, we continued to focus on improving the efficiency of our operations and adding infrastructure to reduce trucking and deliver as much natural gas to market as possible. We participated in 83 gross, 28.5 net wells in the Bakken. In terms of operated wells, the totals for 46 gross and 24.5 net, including 3 excellent ECO-Pad projects that we announced in early October.

One note of interest is the recent completion of a 40-stage frac on a well in southern McKenzie County. We expect to report results to you on this well by mid December.

Overall, drilling times are averaging about 30 to 31 days in the Bakken. And during the quarter, we began completing our Bakken wells with a standard design of 30 stages. Well cost continue to average right at $8 million per well and range from $7 million to $9 million, depending on location and well design.

One of the most positive operating developments in the quarter was the progress we made in installing oil, gas and water gathering systems to many of our Bakken well sites. We also expect to have 2 gas plant expansions coming online by year end, which will immediately process gas already connected and provide capacity for new completions.

By the way, Bakken gas is very rich. 1,500 Btu with 12 gallons per 1,000 NGL included. This contributes noticeably to our economics in the Bakken.

We also added some very attractive acreage in our Bakken position in the third quarter. 22,600 net acres in Williams and McKenzie counties, mainly west of the Nesson Anticline. Many of our strongest wells in 2011 have been drilled in this area, which we refer to as the Williston prospect. 59% of the new acreage is already held by production.

Before we leave the Bakken, I'd like to highlight our $5.62 per barrel oil differential in the third quarter. This reflects the fact that we are delivering a significant portion of Bakken and Red River oil production to markets other than Cushing, Oklahoma. As you are aware, Cushing is an adequately take-away capacity at this time. As a result, WTI is an increasingly unreliable metric of the value of the Bakken oil. By the way, we think the Cushing bottleneck is going to be solved sooner than most expect.

About 60% of our total production in the Williston Basin is piped to markets at Clearbrook, Minnesota and Guernsey, Wyoming where we've been receiving a premium of $2 to $7 per barrel for Bakken sweet. Our Red River Units oil go to the pipeline -- goes by pipeline to Guernsey where it is priced at a discount due to higher sulfur content and lower gravity than the Bakken light sweet. This gives you some parameters on the 60% of our Bakken and River oil that is shipped to market by pipeline.

The other 40% of our Williston Basin oil is shipped to rail -- to market by rail, and most of that is transported to St. James, Louisiana. At St. James, the price basis is Louisiana Light Sweet, which this year has been significantly higher than WTI. We have also begun railing into the upper Midwest and East Coast markets. Railing is significantly more costly than pipe but the premium prices in these markets have more than offset the higher transportation cost.

One last observation, oil and gas marketing numbers are dynamic and changing daily. I just wanted to give you a clear idea of various markets where we are selling oil today and our efforts to deliver to premium markets, given the currently depressed level of WTI.

Now let's shift to talk to the Anadarko Woodford. We had 14 operated rigs working throughout the third quarter, 4 of which were transferred to a short-term by another operator for use until January. We participated in 31 gross, 13.5 net wells in Anadarko Woodford last quarter. A significant well was the Petty 1-16, a 100% ownership well located in Blaine County.

This well extends productive fairway of the Northwest Cana, 6 miles northeast into what is considered the oil window of the play. The well was very strong on test, producing 2.1 million cubic feet of gas and 380 barrels of oil in its initial 1-day test period.

We had a number of other strong completions in the Northwest Cana last quarter, and we are currently drilling or completing several wells in the Southeast Cana, including the first offset to the Lambakis 1-11 in Grady County. This well, the Lyle 1-30, is located 4 miles southeast of the Lambakis, has been completed and is currently flowing frac water back. We expect to have a report on this well and several others available by mid-December.

Another important catalyst in the play will be the Toms 1-21XH well located in Blaine County. This is the first multi-unit spaced well to be drilled in Oklahoma, with a planned lateral twice as long as previous wells. This opportunity to double the lateral length should provide a significant improvement to well economics.

In the Niobrara, we are completing our second and third wells, the Marconi 1-1 and the Perrin 1-10 in Well County, Colorado. These wells are located in the high-resisting force fairway that is rapidly being derisked through industry drilling and development. We have approximately 25,000 net acres leased in this fairway. Again, we expect to report on these wells by mid-December. Indications so far are very positive.

Before turning the call over to John to discuss financials, let's take a quick look at 2012 CapEx and guidance.

93% of our $1.75 billion CapEx budget is again focused on drilling operations, which includes facilities and workovers and primarily on the Bakken where we have clearly -- clearly have the strongest returns. We plan to participate next year in 759 gross, 249 net wells. Of these, 488 gross, 126 net will be in the Bakken. We plan to maintain 24 rigs in the play next year.

In the Anadarko Woodford, we are budgeted to participate in 159 gross, 46 net wells in 2012. We expect to average 10 rigs in the play next year. We plan to keep 1 rig active in the Niobrara with our non-op -- participation included, we expect to participate in 26 gross, 12 net wells in 2012.

Most of the remaining wells for 2012 are in the Red River Units and our Eastern division. These wells have a significantly lower cost per well as compared to the Bakken and Anadarko Woodford. We're expecting production growth of 26% to 28% year-over-year, which will be another big step towards achieving our 2009 to 2014 goal of tripling the company's production and reserves. We're well on our way to making this happen.

Continental clearly has a huge drilling inventory, a strong balance sheet and skilled operating teams. We look forward to many years of production growth, increased proved reserves and additional value creation. We appreciate your support as we execute our growth plan.

John, I'll turn it over to you.

John D. Hart

Thanks, Jeff. This morning, I'd like to comment on our financial results. We had an excellent quarter. Net income for the third quarter of 2011 was $439 million, or $2.44 per diluted share. This compared with net income of $39 million, or $0.23 per diluted share, for the third quarter of 2010.

Continental's third quarter 2011 net earnings reflected the combined effects of an after-tax unrealized gain on mark-to-market instruments of $333 million and an after-tax charge of $16 million for property impairments. Without the combined effect of these 2 items, our clean earnings were $0.68 per diluted share, in line with straight consensus.

We reported EBITDAX of $338 million for the third quarter, a 72% increase over EBITDAX for the third quarter of 2010. For the first 9 months of 2011, we've generated EBITDAX of $892 million, 51% higher than our EBITDAX of $590 million in the first 9 months of 2010.

As we've discussed with you in the past, we decided in 2010 to pursue a prudent derivatives policy that would stabilize cash flows and enable us to maintain a more robust drilling program despite volatility in oil and natural gas prices. This has benefited us greatly in 2011, and it remains a central aspect of our growth strategy as we look ahead.

For the fourth quarter of 2011, we have 644,000 barrels swapped at a weighted average of $86.25 and another 2.6 million barrels with collars ranging from a $75 floor to as high as $97.25. Please refer to our third quarter 10-Q for additional detail on these contracts and the outlying years.

For 2012, we have 9.2 million barrels swapped at a weighted average of $90 and 5.3 million additional barrels with collars ranging from $80 to $97. For 2013, we have 5.1 million barrels swapped at a weighted average $89, and another 8.8 million barrels with collars ranging from $80 to $110.

On the natural gas side, we have 7.2 MMBTus swapped in the fourth quarter of 2011 at a weighted average of $5.40 and 3.7 MMBTus swapped in 2012 at a weighted average of $5.07.

In yesterday's press release, we provided our outlook on operating cost per Boe for the next year. Production expense, we expect to be in the $6 to $7 per Boe range. We further anticipate that production tax will be between 8% and 8.75%. DD&A cost should be between $17 and $20 per Boe. Additionally, we think that G&A per Boe will be in the $250 to $275 range, with additional non-cash compensation of $0.70 to $0.90 per Boe.

Our relocation is a central component of our multiyear growth strategy to develop our liquids-rich inventory. The relocation is already paying dividends in the form of the expansion of our talent-rich workforce and is going exceedingly well. We expect to be fully relocated to Oklahoma City by the summer of 2012.

In terms of our growth, we expect to fund a large majority of our production growth with increased cash flow from operations. As additional cushion, our revolver borrowing base has recently increased to $2.25 million, in line with the growth in our proved oil and gas reserves base. Our commitments remain at $750 million today, which leaves us with $617 million of that being available as of October 31.

Our 2012 guidance is for production growth of 26% to 28%. We set this target based on a desire to limit the extent to which we outspend cash flow next year. If commodity prices and operating cost improves significantly, generating even higher rates of returns, we can easily and efficiently elevate our growth curve.

We are on track to accomplish our goal of tripling production and reserves, and we have ample capital resources and access to new capital to get the job done without significantly increasing our net debt metrics. Capital discipline is a key factor in this growth plan. Under our current plan, we expect to achieve cash flow neutrality in 2014.

With that, I'll turn it over to Harold.

Harold Hamm

Thank, John. I'll just comment on a couple of things briefly before we go to Q&A. A lot of people are interested in what's happening with the Cushing market. And as Jeff indicated, we see recovery at this market a lot sooner than people have expected. In fact, we see this Cushing market recovery beginning now. It's already begun. This market has been disadvantaged due to lack of pipeline capacity as foreign crude came in, primarily through Keystone Pipeline. And basically, what turns it around of course is additional pipeline access, and we see of course 2 things occurring there. One, first of all, is a huge differential that came into effect to provide for deficiency of about as much as $29 per barrel. We see that now being reduced down at -- right around now about $17 below Brent's, the world market price.

Short-term, we see a couple of things happening fairly quickly. The first one would be the existing Seaway Pipeline factor, as I'll call it, helping that disadvantaged market. Conoco of course has announced that they're selling that, and we see several companies interested. And of course, that could be turned around quickly, estimate is 3 to 6 months' time. That could turn around and give short-term relief to the market.

Longer-term, of course, is Keystone XL, the first segment being built from Cushing to Houston, that would provide some of the long-term relief that's needed for this market. So we see that recovering and maybe perhaps quicker than other people generally have thought.

The second thing I'll comment upon of course -- so we mentioned the Charlotte 2-22H well that is in the second bench of Three Forks. Basically, we see this giving us an additional extensive reservoir and, of course, another valid type point to this petroleum system of the Bakken. So we see it as a very, very good plus for additional reserves up here in the Bakken. I think the second bench can mimic the productive capacity of the first bench that we've seen with the longer-producing wells up there.

So with that, I'll turn it over for question-and-answers.

Question-and-Answer Session

Operator

[Operator Instructions] And we have our first question in the queue, and it comes from the line of Scott Wilmoth from Simmons & Company.

Scott M. Wilmoth - Simmons & Company International, Research Division

What I'm thinking about 2012 production guidance you guys laid out, how should we think about oil and gas growing separately throughout the year?

Jeffery B. Hume

Well, I think they're going to pretty well grow in concert from how they've done this year. We're obviously seeing an increase in the gas just due to the plants coming on in North Dakota. So we'll have a little, little jump in the fourth quarter, we believe, late, late in the fourth quarter where we have 2 plants coming on of about 160 million a day capacity that we deliver to. And they're doing pretty well. But next year, with 24 rigs running in the Bakken and 10 in the Woodford, we're going to see about the same type of growth or relationship in gas and oil as we've had this year. We're seeing better productivity in the Bakken, and we expect better productivity with the 30-stage frac. So we should increase our oil components as we go forward.

Scott M. Wilmoth - Simmons & Company International, Research Division

Okay, great. And then when I think about the 2012 budget, what price deck did you guys set that at? And you alluded to it could be revised higher. What price level would we see activity and production increase?

Jeffery B. Hume

We set that at a strip price, and it was a late October strip that we set that -- that at. Scott, I don't have it on top of my head, but it's probably in the upper 80s.

John D. Hart

It's in the range point.

Jeffery B. Hume

Kind of where we're at today.

John D. Hart

We model that in a variety of ways. So we've looked at a number of scenarios for the market, and we've considered the expectations. So as we continue to watch the markets as we indicated, we can quickly and efficiently adjust our plans as we've done.

Scott M. Wilmoth - Simmons & Company International, Research Division

So what price would -- would you guys adjust your plans upward?

Jeffery B. Hume

Yes, we would.

Scott M. Wilmoth - Simmons & Company International, Research Division

At what price?

Jeffery B. Hume

Oh, what price? I think we see a price of $95 and above. We'll probably be -- we'll have additional cash flow to do that. And as Harold mentioned, with the expected turnaround of the Seaway Pipeline that could happen by midyear, we could see the second half of the year have oil prices $10 to $15 higher than they are now at the wellhead. So that would provide a significant cash flow to accelerate the second half of the year.

Scott M. Wilmoth - Simmons & Company International, Research Division

Okay, great. When I think about the second Three Forks bench, what are your additional plans there? And are you guys going to drill a test under an existing first Three Forks bench test?

Harold Hamm

We don't have any current plans to do that. There will be several other wells going forward in that same bench, but we don't have any plan right now just to get under a first bench well to test it like we did at Mathistad. We don't have a plan to do that right at this time.

Scott M. Wilmoth - Simmons & Company International, Research Division

Okay, great. And my last question is in the Charlotte well, where is it located along that north/south area that you guys tested? And was there any distinction in that core, that area, versus the other parts of the play?

Jack H. Stark

The Charlotte is actually kind of centrally located in the cores that we took. It's in 152 north, 99 west, section 22. And it really -- what was really remarkable to us is the fact that in each of these cores, we saw oil saturation in the dolomitic members of the first, second, third and fourth benches. And really, all these cores, we saw it at different degrees, but the first bench and second bench showed the best uniformity development. And then the third and fourth, as Jeff had mentioned, we're a little more localized in their development. And then in some places, it's a little bit -- I'd say that one well, it looked like maybe the third and fourth were absent. But overall, what we're seeing is widespread development of all 4 benches. And where we find dolomite in them, you have oil saturation. So really, the significance of these cores that we've taken in the Charlotte outcome here is that we've really redefined the geologic model for the petroleum system in the Bakken formation right now, Bakken and Three Forks. What we're dealing with -- the whole petroleum system itself includes the Bakken and Three Forks. Initially, we thought all production was really going to be restricted to the Bakken and the upper part of the Three Forks immediately underneath the Bakken shale. And now we've recognized from the cores we've taken that this oil saturation extends all the way down to the base of the Three Forks formation. And that Three Forks gives up to 270 foot thick. So you got a very large -- much larger petroleum system than we envisioned here initially. And so it just adds -- just makes sense that we've got incremental reserves to add to these additional benches here.

Operator

And our next question comes from the line of Leo Mariani from RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just kind of a quick follow-up to what we're talking about with that Charlotte well there. So just trying to get a sense in general. Obviously, you guys have done a ton of wells in the Three Forks/Sanish. And when you guys frac those, have you done microseismic to see how that frac kind of propagates kind of up/down, sort of how far away from the wellbore you think that that kind of moves? Any chance that you've frac-ed into the second bench with any of your existing wells, what I'm trying to get at here?

Jeffery B. Hume

Leo, we have not done any microseis to get vertical heights of growth on the fracs yet. We have done extensive modeling, that's one of the outcomes of our coring -- core work and log sweet work we did on these 6 wells. It's where we can model that. And we have modeled it, and we feel that it's possible we could redesign our frac to get higher frac height and conductivity. Our current fracs, we don't believe will extend down into that at -- 50 foot away is extensive distance for it to go, and it is slower. We saw a slightly higher frac gradient in the second bench on the Charlotte than we did on the middle Bakken well that's in that spacing unit with it. So what we're seeing is higher frac rating as we go lower in the same spacing unit. So I would not expect it to grow down into the second bench. Now we maybe able to get down in the lower benches, redesign our frac with higher concentrations of fluid and more viscous fluid and have that high frac and really up our reserves in the future, but that's part of the future work we're going to be working -- testing on in the future. And I think you'll hear more out of us on that. So we have potential maybe to significantly increase our productivity and reserves out of a single well with a frac redesign and placing the well bore lower in the Three Forks. But that's the work to go forward. At this time, the good news is we have a second bench that's producing that we don't think we've touched yet.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Right. Okay. And do you guys have any plans to test the third and fourth bench at any point in time here? During the year? I guess, next year?

Harold Hamm

Yes, we will. That why this work has gone forward, to see know what productive capacity is through these lower benches. And certainly, we're going to be testing those. And that's why we're not doubling up and testing interference at this point. We'll do it at some point, but we don't have any plan to do it right now.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. Just kind of moving over to the Anadarko Woodford. Just wanted to get a sense of your infrastructure over there. I know in the past, that you've kind of reported that. A lot of the wells that you guys have produced have been somewhat constrained. You guys aren't able to open these up all the way. Just wanted to see if there's kind of any update on infrastructure in both Southeast Cana and kind of Northwest. And just trying to figure out if most of your wells you still think are pretty choked back on the production here?

Jeffery B. Hume

Well, quite a few of those in the Northwest are choked back at this time. We have entered into a contract that's allowing a midstream company to put in a much larger gathering system to alleviate that chokepoint, if you will, of using existing gathering. And they are on their way to getting that done. And I think by probably second quarter, we'll be seeing relief from that increased gathering system size. In the Southeast Cana, we're currently up to bid on that. As you realize, we haven't run very many rigs down there. But our testing has shown -- all of the area in the Southeast Cana with strong productivity, extremely rich gas and strong liquid component -- free liquid component, if you will, of crude oil and condensate. And so we're out to bid right now. We're working with several different companies on bids for that, to get that system in place before we ramp up the rig count in there, which we'll be doing through 2012 and beyond.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And does that also include bids for potential processing plants? Anywhere around there? You guys think you'd make better economics, I imagine, by getting the gas processed? It sounds like you're just selling it rich now.

Jeffery B. Hume

No, that's exactly what this does. It's not only gathering, but it's plant construction. Once we contract with the midstream, they'll be putting larger gathering systems in to handle the high flow rates that we have from these horizontal Woodford wells, initial flow rates and also process the rich gas through cryogenic processing. And both areas will have cryogenic processing capacity as part of that contract.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, got you. Any kind of planned sort of asset sales in the future as well?

Jeffery B. Hume

Well, don't have any definite plans right now. We are selling some acreage that's in fringe areas and does not have a large ownership position in. So we are marking some of that. But no fixed plans at this time, although that is an opportunity that we do have, is to sell some non-key assets.

Operator

And our next question comes from the line of Brian Lively from Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

A follow-up question on the second bench Three Forks. What's the gas-to-oil ratio and water cut on the well?

Jeffery B. Hume

Yes, the GOR on that is, I believe, currently in the 1,400 range.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And water cut?

Jeffery B. Hume

The water cut, I don't have in front of me. But I -- Jack, do you have a feel for that?

Jack H. Stark

I don't. But consistent with what we see in the area. Nothing abnormal about it at all.

John D. Hart

Right. Yes, we're pretty early in there. We're still getting frac water back, Brian. So we have probably 35%, 40% water still coming back in that area. We expect it to fall down to a 8% or 10% water cut.

Jack H. Stark

And, Brian, I don't know if this was where you're going with the question, but maybe you were thinking, as you go lower in the system, you might pick up water. In these type of systems here, we're talking basin centered oil systems, those water lakes don't exist. And so we're dealing with essentially an overpressured cell of oil that is basically stratabound by the overlying lodgepole[ph], which is a tight sealed rock on the top and the Nisku Formation, which is a tight rock that seals the base. And so this oil that's been generated from the shales in Bakken essentially has been unable to escape from the basin. And so that's why it's overpressured and it's saturating every dolomite, any kind of rock that has any kind of porosity and permeability. They're still tight by conventional standards, but it's saturating any kind of rock that has any kind of perm and porosity at all. And so we don't see water being an issue here at all.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Yes, I wasn't expecting there to be aquifer, but I was thinking more in the sense of a capillary pressure or relative perm impact. But you guys think the sourcing is still the lower Bakken?

Jack H. Stark

Oh, yes. I sure do. And in fact, the interesting thing is that the Nisku below it is normally pressured and the lodgepole[ph] above the Bakken is normally pressured. And so again, that -- and we don't see Bakken oil above it and above the lodgepole[ph] section essentially. And so what we see is that the generation and the oil saturation we've gotten here is clearly coming from the Bakken shales.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then the trap mechanism is the same?

Jack H. Stark

Yes. In fact, what's happening here, as you generate the hydrocarbons, you're overpressuring the shales and the oil will move out in any direction of lower pressure. So it's going to move to perm and porosity. And so it's moved up sideways and down, as far as it can go. And so the oil is migrating through fractures down through that first bench in the Three Forks, into the second, into the third and down into the fourth. And when it hits the anhydrides at the Nisku, it just can't penetrate the Nisku. Anhydrides are very, very tight rocks and so essentially, the oil moves down as far as it can and it starts moving sideways, out in these dolomitic members of the Three Forks.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

That's great. Thanks for explaining it's pretty easy to understand. I have a couple more, just on the -- in looking at your 2012 CapEx guidance, and if I compare that to sort of the Q4 run rate of about $600 million, it seems like you guys are going to -- are planning to spend maybe $150 million or so less per quarter next year. Yet, the rig count doesn't seem to be materially different versus where you guys are now. I know there's a few less rigs in the Anadarko. Now how does that reconcile?

Jeffery B. Hume

Well, the biggest thing is we were behind on completions. We have a tremendous backlog of completions that we're working out right now, and our carry-in going into 2012 is going to be very strong. So during 2012, maintaining a fairly flat rig count throughout the year, we're going to have a strong carry-in value that half the dollars are spent in 2011. So that's kind of how the model works, Brian.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. So it seems like with -- some are rig count, and then you still have some completion dollars next year for the same production growth. Why wouldn't...

Jeffery B. Hume

Well, our land cost is also down quite a bit. So you need to look at the dollars going into the drilling and completion. We have 93% of our dollars, are going in, in 2012 versus what we have done in 2011.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And just last for me, you touched on a bit with the asset sales, but you guys have, in the past, been a bit leery of really drawing down the revolver. I know, with the current budgets, you're drawing down a bit next year. It's not undoable. But aside from asset sales, what are -- are there any other plans? Or are you guys just comfortable drawing down?

John D. Hart

Our revolver, we've got it very lightly drawn down. It is a tool that we've historically used. And where interest rates are now and where they'll be, I think we're certainly comfortable using that. But we've got a variety of options. We've got increasingly positive cash flow. And frankly, we expect oil prices to continue to improve into next year, and that's going to generate higher levels of cash flow also. So we've got a lot of strong funding options, and we can maintain our financial strength.

Operator

And our next question comes from the line of Noel Parks from Ladenburg Thalmann.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

I got on a little bit late, so I apologize if you already covered this. But with the success you had in the second bench of the Three Forks, I did hear you talk a little bit about looking at changing your frac design. Are there implications for -- well, I guess I'd say sort of best case and worst case, what would your options be for exploiting the multiple zones? I mean, does this mean greater density? Does this mean sort of pad drilling that would go after different benches while you're drilling simultaneously?

Jeffery B. Hume

Well, I think what it provides is that -- what we're seeing is, as Jack described there and you may have missed it, Noel, we have a system that we are seeing as saturated 270 feet thick, up to that thickness, saturated with oil. And we've just tested this second bench and have productivity. We had slightly higher frac grade in that rock than we did in the upper bench in the area, so we feel like the frac grading is increasing as we go down. So more than likely, our current fracs that we are doing, are not touching, effectively draining, anything from the second bench. Once we test the third and the fourth benches, then we can start working on frac redesigns. Can we frac that entire 150 to 250-foot or 200-foot interval with one frac and build a kind of conductivity through that to drain it? If that's the case, we could see reserves double or triple in a single well draining that rock. That's the potential you have. Now a caution, that's what we have -- that's what we're working towards, and it's going to take quite a bit of work, and we'll be doing that over the next year or 2. It's going to take quite a bit of time. In the meantime, we're working very, very fast across our acreage position with middle Bakken and upper bench wells, and we'll be sprinkling in some of these second, third and fourth bench wells and probably be looking at the redesign fracs after we get a few of those done and understand the productivity of these lower benches. Out in the future, I think you're spot on of where we could go and that would be have wells with, perhaps, double the reserves for the same cost or slightly more cost with a redesigned frac. So that's the science going forward. It's not what we're declaring we're doing today.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Got you. And in the Charlotte, just to refresh my memory, was it the Bakken productive -- or expected to be productive there? Or had it thinned out in that area?

John D. Hart

No, it's productive. Our Charlotte 1...

Jeffery B. Hume

Charlotte #1 well is a Bakken well. It's a middle Bakken dolomite well.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay. And then -- I mean, can you talk about, again sort of maybe best case and more conservative case, number of wells per section we might be looking at? If we were thinking in much of the play, I guess now people are talking about at least 3 each Bakken and Three Forks. I mean, are we talking about 3 Bakken and still more Three Forks?

Jeffery B. Hume

Noel, we feel pretty comfortable that we'll be drilling 4 on each horizon. And we'll obviously be doing that very much like we're doing in Elm Coulee now. We drill 3 within the unit, and then we'll do a well on the boundary of both sides. So you have a half-well on each side of the space unit. So you have a net 4 wells in each horizon. And right now, I would say, I'm very comfortable that where the Three Forks is developed, you'll have 4 in the middle Bakken, 4 in the Three Forks. And if we can -- if we cannot tie the first, second, third and fourth benches together with a common frac, you could potentially have 2, 3 or 4 additional separate zones that you could frac 4 wells per spacing unit so it would be tremendous. So obviously, we're going to work very hard to come up with a design where we can either drill a multiple lateral or do a redesign frac to have conductivity height that would access the fluids from all 4 of those benches if they're productive in an area. So for right now, I think we're fairly comfortable we'll have 8 wells per spacing unit in the middle Bakken and the upper bench. And this first test on the Charlotte gives us indication we'll probably have up to 50% more wells to drill if we can't connect those. And so this 50% increase in reserves at minimum, and then as we test the third and fourth benches, even more.

Jack H. Stark

And, Noel, I would just add too. This is Jack. I just wanted to make sure, when we're talking about these benches over that, say, in the Charlotte we cored it, and we had 220 feet of Three Forks formation. And within that, we had 4 benches and -- but the reason we're suspecting these do not communicate is that there are shales separating these dolomitic benches. These aren't -- it isn't just oil saturation from top to bottom. We actually have some shale separation between the dolomitic members that represent the targets for these benches. So we had about 114 feet of oil saturation on the 220 in that Charlotte well. And I think that, as Jeff said, we're still evaluating whether or not we're going to need a wellbore in each of these benches, or whether or not we could somehow combine it to price.

Operator

And our next question comes from the line of Marshall Carver from Capital One Southcoast.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

A couple of questions. On the production guidance for next year, could you talk some about the shape of the 2012 production curve? I mean, this year, was very -- the growth was very back-half weighted. How do you anticipate it being next year from quarter-to-quarter?

John D. Hart

Well, with a constant rig count, we should see pretty steady growth throughout the year and not have it back-weighted. So that's what we would expect. We're going to have fairly steady completions each month. Outside of weather interruptions like we had this year, I think you would need to model it as continuous growth throughout the year on -- just adding those completions in.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

And how many wells do you plan on completing next year versus the number that you plan on drilling in the...

Harold Hamm

Right now, it's a little bit nebulous on the number, but just short of 250 wells is what it looks like.

John D. Hart

Net-net wells, Marshall. That's for next year, and we're going to be -- this year, we're going to be in the 180 to 210 range, something like that on completions, just kind of depending how the net wells and how it finishes. So we'll have slightly more completions next year, and that's just due to the carry-in. Last year, we didn't have a strong carry-in because we didn't have the rig count. We added rigs through the first quarter and ramped that up. And then this year, we're going to let it flatten out a little bit. We're letting infrastructure catch up with us a little bit, not press it any, work on our efficiencies and cost and kind of see where this oil price goes. That's a big swing for us, and we think that it's going to make a big change at midyear. We'll kind of see where that's at. But right now, we're taking a conservative approach and setting our budget. We have strong growth for that approach. We're not running up our revolver very much with it and have great metrics. So that's our plan today.

Operator

And our next question comes from the line of Brian Corales from Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

Can you maybe talk about the -- you talked about the cost in the Bakken at $8 million. Does that include the 30-stage frac wells?

John D. Hart

That is the 30-stage frac well and as I stated, that will range from $7 million to $9 million, a little over $9 million, depending on where we're at. Some areas of the field, we can drill faster and has a lower frac gradient. So your hydraulic horsepower charge is less on the frac. Some areas where we're deeper, we have to put a little heavier pipe in to handle that frac grade in and pay the higher horsepower. So that's the variation in there. And that's pretty much 30-stage all the way, because that's our base now. Our base is 30 stages. And as we mentioned this morning, we have performed one 40-stage frac down in southern McKenzie County to test that area with a 40-stage.

Brian M. Corales - Howard Weil Incorporated, Research Division

And have you all started to see pressure pumping cost kind of flatten yet?

John D. Hart

Yes, we have.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. Has it declined?

Jeffery B. Hume

I think it's on the -- I think you're right on the edge, if you will, of starting to see a decline. There is quite a bit of competition. We, in fact, have been using 3 primary providers. We have several others knocking on our door who want to get an opportunity. And at the end of the day, when everybody's providing good service, the cost really come into play then.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And you also mentioned on your capital budget, with lower cost or higher commodity that you'd look potentially increase activity, where would you increase activity? Would it be in the Bakken?

John D. Hart

I think that's where we would increase it at. One thing we may note is in some cases, we've got -- if you look at our acreage base, we've got acreage with the needs to be HBP'd and we're diligently working on that. Some of that may be in a 40% to 50% working interest range. We also have quite a bit of acreage through some of our recent acquisitions of lease acreage where you're 80%, 90% working interest. And we can, utilizing the same rigs, we can increase our capital spend and production rates pretty quickly. So we think that's a big advantage.

Operator

And our next question comes from the line of Joe Allman from JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Just a follow-up on the second, third and fourth benches, so does this result from this well make you want to slowdown the activity for the Three Forks, just so you can figure out how you're going to develop it going forward, and maybe the early part of next year of through next year, focus more on the Bakken? Because it seems like this result really potentially changes the way you develop Three Forks.

Harold Hamm

Well, the productive capacity of course of this zone makes us want to continue development of the Three Forks, gives us a lot of choices on how we go about that. But we will quickly -- and basically, the way we do it is through actively drilling out there, testing the concepts that we develop here. So I don't think it slows us down a bit though, if anything speeds up the development within a particular area.

Jeffery B. Hume

In fact, Joe, I think the success on the Charlotte 2 is going to encourage us to drill more second-bench wells, start working on the frac redesigns, see if we can increase the reserves per well and hopefully, for the CapEx we have laid out for 2012, we'll have higher reserve and higher productivity. So that's what we're looking at. So there's a lot of upside we think we'll have in 2012 as we continue to test the Three Forks' lower benches. And so that, I think, is more the other way that we're going to be encouraged to drill more Three Forks wells to do more testing in there with the solid results.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

So it seems then that -- it seems that pretty much right away, you're going to start making adjustments. So instead of drilling in the middle of the first bench of the Three Forks, is it true that the next few wells are -- early in 2012, you're going to try the lower part of the first bench and then try some other things maybe in the second or third bench?

Jeffery B. Hume

We'll be making adjustments, so I don't know if it's going to be all at once. But we do everything cautiously, and we weigh it up and what we're doing. We have a lot of plans in place, and we just don't turn on a dime with that. But we're going to take specific steps to test the second bench, see if we can design a frac that will touch multiple benches. We'll be looking at the third and fourth benches as we move through the year, and I think it'll be not a drastic move to that, but I think you'll see a sprinkling that in as we move ahead with our development.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Will you be using microseismic for those wells just to see where you're getting production from?

Jeffery B. Hume

Not right now. One of the tough things on microseis is having a wellbore situated that you can use to have sondies ph] down in the well to see the vertical height. And most of this area, you don't have wellbores available, where we're working at, in new areas that don't have developments. So that's one thing we may look to doing at some point. But right now, we don't have any on the schedule that I'm aware of where we're going to be running microseis.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you. And then is the Three Forks across your acreage variable in any way such that in certain parts of your acreage you don't necessarily have a second bench or third bench or fourth bench?

Jack H. Stark

Well, Joe, we're working on assessing that across our acreage. There aren't many cores out there in the Three Forks. We've got some of the few that have been taken out there through the whole interval. So we have to use those logs or those cores and compare them to logs and then do the mapping. What we see is the first bench is quite widespread. The second bench is equally widespread as the first and pretty uniform in development, based on our cores and what we see in existing logs. And the third and the fourth, as we said, is a more localized in their development, still cover broad areas, but we don't see quite the uniformity of development across the basin. So we'll ultimately have maps on each of those benches and be able to give a better perspective on that down the road.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, that's helpful. And then a different topic. So with the increased number of completions you expect next year, does that require you to bring in additional frac crews?

Jeffery B. Hume

Well, we think we can handle it with -- we have 4 dedicated crews and a fifth that is also pretty much at our disposal. And that is without adding some of the existing frac crews that are in Williston. And if you talk to most of the service providers, they're continuing to ramp up to meet the demand. We think that we're going to be fine.

Operator

And our next question comes from the line of Subash Chandra from Jefferies.

Subash Chandra - Jefferies & Company, Inc., Research Division

Curious in 2012, your outlook for production from the non-core assets, specifically Arkoma, some of these -- other Mid-Continent looks like there's Q3 somewhere in the order of 150 million a day. And you seem to have done a fine job of growing all the non-core as well as the core and if you expect that's going to continue into 2012.

Jeffery B. Hume

Well, we think -- our challenge with our base assets -- we hate to call them non-core because we still try to put quite a bit of focus on it. But we do have some decline, modest decline, built in on those because we're not spending a lot of capital. But that being said, we've got several production optimization initiatives underway that -- we're going to continue to challenge our teams to do just what the Red River Units team has done, and that's to keep those volumes flat.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. Yes, I mean, these are just my -- if those volumes were flat, sort of 27% growth rate seems light for next year. Any comment?

Jeffery B. Hume

Well, we don't -- it's not in the bag. Obviously, we've got a lot of things underway, but we feel pretty confident about achieving this guidance at this point in time, and we'll see how our fourth and first quarter go weather-wise. That's going to be one of the big drivers.

Subash Chandra - Jefferies & Company, Inc., Research Division

Got you. Okay. And then back to the benches. Believe it or not, a few more questions here. First, so when I'm thinking about 1, 2, 3 and 4 and optimizing frac techniques, I'm curious, if we had to put reserves on it per well, is it been something that is probable that you might see a 500,000-barrel Three Forks well turn into a 1 million barrel Three Forks well? Or if these are sort of equivalent benches, you have all of them, 500,000-barrel becomes a 2 million-barrel Three Forks well. So is that, A, what is possible out here? And second, I guess at the Bakken, some of the oil in the Bakken, I guess, migrating down, which I guess is rare but happens here because of the seals and so on. Is there any implication of how a frac might travel? Does it also make it easier for frac to head down and be more effective in the deeper, lower parts of the Three Forks?

Harold Hamm

Yes. We're going to break it after the 2 parts, Subash. First of all, in this petroleum system, what we have is hydraulics through this kitchen area that most of our acreage is located in. It actually pushes this oil vertically downward, out of these shales and to the base of the Three Forks and then spreads out laterally. And so, of course, drainage, when you look at draining these reservoirs, if we can get where we're producing from a lower point over the life of this field, it's going to be a tremendous advantage just due to gravity and producing these reservoirs. So I'm going to turn it over to Jeff, get his engineering view as to what he thinks ultimately that, that's going to add, a feeling of production -- productive capacity as we go forward.

Jeffery B. Hume

Yes, Subash, on your question on adding the additional benches and if we are not effectively touching them now, which we do not feel we are just from early, early data, I'm very cautious here. This is our first well to be drilled in the lower bench. But we did see a higher, slightly higher frac gradient than we normally see in the Three Forks in this, the upper Three Forks bench in this area. So as we move forward, your comment about could this 400,000, 500,000 barrel well, 600,000 barrel well double. Absolutely. If we can get conductivity between the 2, as Jack described, there is shale in between those and the key is going to be having enough profit in there placed that we can effectively drain the 2 of those. So frac modeling indicates that we can do that. Now frac modeling is good to a certain degree then you just have to go out and put it into practice. So we're going to continue to tune our models as we frac these second benches and third and fourth benches and test those, and then we'll be changing frac designs, trying to tie them together and see if we can tie 2 of them together. And hopefully, we'll be doubling that and going -- having 1 million barrels, 1.2 million-barrel completions with not much more cost. Obviously, when you change a frac design, you ask more -- add more viscosity, maybe a larger fluid content and more profit, the cost may go up there. But proportionate to the reserves you gain, it'd be a home run. So that's what we have on our plate to work with, completion engineers are working with right now, and reservoir group, and we're going to be working towards this. So I think that's the upside we'll have and hopefully, over the next year or 2, we'll be unlocking that and do it fairly, fairly quickly.

Subash Chandra - Jefferies & Company, Inc., Research Division

And so I guess for us, monitoring or well watching, if you will, that, that type of reserve upside will be apparent from, of course, the IP, but more importantly, to the decline curves of the well?

Jeffery B. Hume

Yes, more. The decline curve is the most important thing. We've started downplaying these IPs a long time ago because you can make them say whatever you want them to say. We really need to look at the decline curve. The IP gives you an indication of productivity, but then you have to look at decline curve and what you're getting out of that well long-term. The cume [ph] over that first 90 days, 180 days is really, really important.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. And then just a Cana question here, talking about decline curves. Can you comment on your sort of longest producing Cana wells? What you've seen sort of -- first the 30 day rate? And then what you've seen, say, day 1 till yesterday-type numbers on declines there versus -- are they very similar to the Arkoma and how it might vary maybe at the Bakken even?

Jeffery B. Hume

Well, our first well, the Brown 1-2, is made about a B 1.5 [ph] and 19,000 barrels of oil to date. It came on in late 2009. It was an early well and is doing very well. Our Dana well, offsetting -- that's been on a little less than a year, or right at a year. It's made about 7/10 Bcf and 16,000 barrels of oil. And that's down in Grady County. We have some of the new wells like the Lambakis, that's farther south. It's holding up very good on oil rates. it's about a 8 Bcf equivalent well and it's hanging in there pretty strong right now. So we're seeing the Anadarko Woodford to have flatter declines than the Bakken per se, and that's just due to a little bit better permeability and that fracture salacious shale. So it's more of a silica reservoir, silica-based reservoir than the shale that you have in some of these other gas plays, and it allows us to produce these liquid-rich areas. So we're getting pretty excited about that. The Petty well is really pulling off strong. As I just said, the Lambakis well's pulling well. We have a -- the Dana well is holding up real well on oil production and is doing well. And so I think we're seeing a little bit better perm in the Woodford overall and a little flatter decline. And that's allowed us to have the reserve picture that we have.

Subash Chandra - Jefferies & Company, Inc., Research Division

And what does that oil sell for?

Jeffery B. Hume

In Oklahoma, we're probably getting around $3 to $4 under WTI right now at the wellhead. And we're seeing WTI increase quite a bit. As Harold said, it's improved. Its spread has improved about $10 in the last 2 weeks.

Subash Chandra - Jefferies & Company, Inc., Research Division

Yes, it sure has. And then one final one. So in the Cana, you're producing out of the shale, but you're also producing out of the interbedded, I guess, silica, which -- is it carbonate-rich at all?

Jeffery B. Hume

No, it's a silica-rich shale, and it's -- in some areas, silica count's higher than the clay count in most of that area. You have an organic clay, and that's where the hydrocarbon comes from, but then there's a tremendous silica component. Some of the Woodford has a -- very heavy with chert, and chert's brittle and breaks very easily under stress and therefore, you have storage within the fractures and that chert. So the chert and silica micro fractures, what we're -- the storage system in the shale.

Subash Chandra - Jefferies & Company, Inc., Research Division

And the clay content, do you have a percent how it might vary north to south?

Jack H. Stark

Really, Subash -- this is Jack. We see that the lower half of the Woodford is much more clay rich than the upper half, just to put it simply. And the silica content in the upper half tends to be very high, and the lower half tends to be low. So I'm going to say below 50% in the lower half and above 50% in the upper half. And as Jeff said, that silica content really gives you the storage and the deliverability, and so that's really the significance because it's all in one system. You got the generation and the storage all within one formation there. We target this silica, or the more siliceous zones due to just higher deliverability coming from those zones.

Operator

And our next question comes from the line of Hsulin Peng from Robert Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Just a quick brief question, a follow-up to your 2012 guidance number. I want to understand your thought process of how you balance between CapEx and production flows? I think one of the factors you mentioned is how much you want to outspend cash flow. So I was wondering if there is a target that you tried to aim for in 2012? And also, how do you think about that in 2013 before you turn cash flow neutral in '14?

Jeffery B. Hume

Well, we're trying to put our cash flow to work on our highest-return areas. We're looking for capital efficiency and growth. We have a 3-year plan of tripling, which is a 24.5% annual growth. So we're wanting to achieve a minimum of that. With our inventory, as strong as it is, we're trying to put as much of that, those dollars that we have, available capital, to work in those areas to grow that because we have almost a multi-decade inventory right now to work on at the current rate. So obviously, we have the opportunity to increase that as we grow our production, and that's our plan. A static snapshot, we'd go to maintaining our cash flow, not bringing anything else in. We'll go to a cash flow-neutral position in 2014, maintaining those growth rates of over 25% annual growth rate. Obviously, when we have the opportunity to accelerate it with the inventory we have, we're going to try to do that. So we have increased crude pricing or natural gas pricing in the coming year. We'll accelerate our spending levels to grow that. So it's a balance of available cash, putting it to work in highly efficient opportunities where we're seeing -- we're seeing 40% to 60% rates of return in our core areas of the Bakken. Our Niobrara, we're going to see -- potentially have 60% to 100% rate of returns in some of those areas. The way it's looking right now, we'll just have to get a few wells completed to see if the numbers hold out. The Woodford, we're seeing 25% to 35% rates of return today. And with the cross unit spacing, we're going to be able to kick that up another 15% on rate of return. Because of capital utilization, we'll be much more efficient in that. And so we're getting pretty excited about some of those. We have several opportunities to really improve our capital spend efficiency, and we continue to work with that. Back in the Bakken, one of the things -- one of our plans this year is, in holding the rig steady, is to improve that inefficiency. As we stated, our drilling time is in that 30 to 31 days right now. We know we can improve that in the 20-day range by just working on efficiencies. We've done that before when we had a lower rig count in the basin. And it's not just Continental's rig counts, everybody's stressing the system. And the system is catching up, the infrastructure's catching up. People are moving into the area. As Rick talked about the frac crews, many more frac crews were moving in. There's more rig-moving crews moving in and a lot of efficiency is being built out. Rail efficiencies are getting equipment in. So I think you're going to see our cost come down just due to that efficiency as we go forward. Our model is based on what we're doing today. And so that's how you have to model is what you're actually doing. And so I think as time goes, as the year goes on, I think you'll see improved capital efficiency. Hopefully, we'll blow out and have higher production than we're forecasting just due to that efficiency of capital spend. And that's our plan internally. But today, we have to model on what we're doing today.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Right. No, I certainly understand that, that you have a great opportunity set. I was just wondering if there's like a magical target number of amount that you want to outspend in cash flow by -- just looking at my numbers right now, it looks like next year, you'll outspend by maybe $300 million to $400 million. So I didn't know if you have a target. And I know you said that if prices go up, then numbers could go up as well. But I was just trying to get a better feel for it.

Jeffery B. Hume

I wouldn't say there's a magical number. Let me step back for a second. $300 million, $400 million, I don't disagree with the range of that. I think that can improve when we see the commodity prices come up as we expect later in 2012, mid 2012. We're very focused on our economics and in maximizing our economics. We have a significant tremendous long-term asset. If we can get a little better price, that only maximizes that economic situation over the long term. So we're prudent in that, and we'd like to see some of that come. We also have infrastructure at North Dakota that is rapidly expanding and being added to it, the roads and the trucks and the other things in North Dakota that are improving significantly. Those help to improve our efficiencies, which also will then benefit our economics. Right now, we've got a tremendous amount of cash flow and flexibility. Could we spend more without overly levering the company? Yes, we could. We've always focused on keeping our debt metrics relative to cash flow and certainly less than 1.5, and we're well south of that currently. We're right down around 1x cash flow. So we have some flexibility there. But beyond a target metric, it's more the improvement we want to see in oil prices, the improvement we want to see in service company cost and the additions to the infrastructure.

Operator

And our next question comes from the line of Mike Jones.

Mike Jones - Imperial Capital, LLC, Research Division

This is Mike Jones from Imperial Capital. Just wanted to ask on the Red River Units. I guess you've touched on keeping it kind of flat, but you're back at mid 2009 levels. Should we expect some producers to come off as you further optimize? Or just sort of declines from here?

Jeffery B. Hume

Well, we think we have capacity to continue to grow. We've added -- in the Medicine Pole Hills and Buffalo area, we've redeployed some compression we had in Cedar Hills. That will take about 9 months' lag time from when start injecting to we start seeing results from that. We've been injecting there for 6 months roughly, so we're hoping to see some improvement there. That will allow us to change some patterns, possibly drill some wells get better sweep efficiency in those areas, and we have capital allocated for doing that. In the Cedar Hills field, we continue to drill more density and convert currently producing wells to injectors, and our new wells will become producers. So we're tightening the density of the spacing and getting new patterns, if you will, flood patterns. That has a lag time of around 6 months also. From starting injection, you convert the pattern about 6 months and it comes on. So we have a series of patterns, if you will, through Cedar Hills that are at various stages of being flooded. And they're just working better than we had planned. And that's very good news. And so we're seeing -- that team has done an outstanding job of balancing fluid going in versus fluid out, making sure we're lifting all the fluid from those wells. And we're modeling a little bit of decline in that area and the units this year. Well, I think those guys will probably make me look bad again and outperform. But we'll just have to see.

Mike Jones - Imperial Capital, LLC, Research Division

That's great. Is it possible to ever reach 17,000 barrels a day as you we're thinking maybe 2 years ago? Or how does that kind of set for peak production?

Jack H. Stark

Well, we've been real close to that number, and it's beyond our earlier expectations. And so we keep going upward. So we just have to wait and see what that turns out.

Mike Jones - Imperial Capital, LLC, Research Division

Okay, great. Final question on the oil window of the Anadarko Woodford. I am not sure which well name it was but the 380 barrels per day. How are you seeing in the Northeast versus the Southeast and optimizing completions in this higher liquids flow areas?

Jeffery B. Hume

Yes, I think that's a good question. In the northeast part, the well you're referring to is probably the Petty well. That's a well at IPed at 380 barrels a day and still producing well over 200 barrels of oil a day. It is a shallower interval. As you go to the south and west, you're plunging into the deeper part of the Anadarko Basin. So we do see some lower trading ph] pressures there, and the order of magnitude is probably in the 1,500 psi range at 80 barrels a minute.

Mike Jones - Imperial Capital, LLC, Research Division

Okay. So If you look at the pressure differential, when are you going to have that lift? Do you think to the Petty well?

Jeffery B. Hume

Could you repeat your question?

Mike Jones - Imperial Capital, LLC, Research Division

Just regarding artificial lift, are you going to have to put that well a pump relatively quickly? And would you...

Jeffery B. Hume

No, we do not think so. Those wells are staying -- they're flowing for quite some time although -- we do have a handful of wells that we have put. We have put on a gas lift, and those are in some of our earlier wells. But in some of our more recent wells, we have not seen that.

Mike Jones - Imperial Capital, LLC, Research Division

So do you guys expect to be talking about a potential oil window as you go forward and drill more wells kind of outside the gas condensate? I'm trying to understand.

Jeffery B. Hume

Yes, I think that's accurate. And the other thing I'll say is that we're still learning -- we're still fairly early in this play. And it's really exciting about, what we're learning. The last 6 months we've been very encouraged with the amount of liquids that we've seen in some of our wells and -- go down to the southeast part of the basin, we haven't talked about it a lot, we did mention it in the press release, but the Lyle well is flowing backward. We'd hope to have the well going down the cell's line actually today that we've been slowed down a little bit with some downstream issues with the gathering system. But the preliminary results are very, very encouraging, even compared to the Lambakis. The Lambakis is still 3.5 million a day and doing very well. It's flattened out there. So as Jeff alluded to earlier, our first look is we're looking at 8 Bs plus down there. So a lot going on in the Anadarko Woodford. We're trying to really fine-tune where some of the more oily areas are, and we think we're making some real progress there.

John D. Hart

And, Mike, also on these oily areas, we're seeing a higher Btu gas and seeing a real nice premium on that gas price. And so I think we'll be -- with the move we're making, you hit right on. We're identifying through our drilling the richer liquids area of the Woodford play and will, over time, be identifying that more precisely, putting more of our fleet in that area and growing that. And I think you'll see internal rates return, improve significantly in the Woodford as we move forward this year with a combination of that movement and identify the cross-units that we identified. At this time, we've got over -- with the seismic we have, we've got over 48 of those cross-unit wells identified that we'll be spacing and drilling. We'll be starting our first well, that Tom's well, drilling it in the next couple of weeks. And it's going to be huge change, a huge change for us. Tom's well, by the way, offsets our Petty's, so we're expecting fairly high production rates of liquid on that and very rich gas. So it could be a big game changer, so be listening to that here in the next quarter.

Operator

And our next question comes from the line of Andrew Coleman from Raymond James.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Just had one question,I know there's been a lot around the Three Forks here today. I guess I'll just focus on the ground level here. Knowing your ECO-Pads are a certain size, could you refresh our memory what the sizes are? And I guess, if you're going to go with bigger fracs, will you need to expand the size of that footprint to able to get all the kit on location? And second of all, do you have -- what offerings[ph] do you have that kind of get more well density if you start drilling multiple benches out of the Three Forks. I mean, can't -- how much I guess of a cost savings do you think that might lead to as you get a little more densely packed on those pads?

Jeffery B. Hume

Andrew, we don't expect to have any effect. If we change a size of a frac, it'd just be the amount you pump in each stage and it wouldn't require a material change in the surface storage for any one stage. As we go to density drilling with the ECO-Pads, currently the rigs are set up where we drill 4 wells on a pad. We feel like we can reconfigure those to drill as many as 8 on a pad if we need to. But it'll take some reconfiguration of the rig equipment to handle that. Obviously, in that case, we would be increasing the pad for the number of wells but disproportionate to the number of wells. You're not doubling the pad size to get that. So that will be out in the future as we start going through and harvesting with those rigs. We're currently, I think in next year's plan, we're going to have 4 to 5 rigs running ECO-Pads. The rest of the fleet's going to be still pretty well on a single well issue, working acreage that is not currently held by production but in proven areas. So we're pretty excited about that. And I think the ECO-Pad drilling, I don't think will be a huge change in location size. If we should -- hopefully, we can come up with frac designs where we can tie more of the Three Forks resource goal that we're -- we just took our first step into learning what its potential is. I mean, we've very excited with this point, but once we see -- this data point, but once we see a few more data points and a bit more of our design results as the completion guys change their designs and work with that, it's all upside.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay, great. And then I guess I'll sneak one last one in here. What recovery factor are you -- do you initially think works for the Bakken and Three Forks?

Jeffery B. Hume

Probably in the 5% to 8% recovery factor, something in that. So it's fairly low. It's a real, real low perm, low porosity rock. And we just don't get a lot of the oil in plays out.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay. Yes, I've I heard I guess a 4%, I think, was yesterday's at Eagle Ford I think? So kind of -- just still a lot of room then for downspacing and additional technologies.

Operator

And our next question comes from the line of Dick Kenvic [ph] from Keeley Asset Management.

Unknown Analyst -

Clarify it for me. Are those 4 benches part of the Three Forks/Sanish?

Jeffery B. Hume

Yes. They're...

Jack H. Stark

[indiscernible]

Unknown Analyst -

Oh, they are? Okay. So you've been just drilling in the first bench? Is that where the production has been in the Three Forks/Sanish?

Jack H. Stark

You bet. Dick, this is Jack Stark, and I just wanted to clarify. The Sanish is a real localized term that really should go away. It was a -- back, early on in the basin, a big [ph] were drilling into the Three Forks, are really drilling deeper. But they would run into occasionally a little localized silty development called -- that they ultimately called the Sanish right at the top of the Three Forks. All right? So it really is -- really come and go. It doesn't develop a lot. And so what we see out here is just that we've seen these 4 benches from the core work we've done, and these 4 benches are, say, on average, around 50-foot thick, with about half of that being dolomitic, okay? And...

Unknown Analyst -

Half of it being what?

Jack H. Stark

About half of it being dolomitic. In other words, reservoir-quality rock. But when I say quality, it's low quality because it's very tight rock. Okay? But it is reservoir rock in this Bakken petroleum system. And so, yes, all 4 of them are part of the Three Forks. And keep in mind, the Three Forks does get upwards of 270 foot thick in the basin. So we're talking about a good-sized interval out here of really new appreciated reservoir potential out in the Williston Basin. I mean, this is a game changer for the Three Forks, and it just adds a lot of upside to the Three Forks that we did not previously appreciate.

Unknown Analyst -

Yes. Would it ever be possible to drill and complete in all 3 or 4 benches?

Harold Hamm

Well, it would -- I think you're talking about mechanically, and it certainly is. We've seen people try to double up and complete the middle Bakken and the Three Forks as well in one well. We don't believe that's cost-effective. We think there's other ways to achieve the results, particularly through the Three Forks perhaps. And we'd probably still see additional wellbores in the middle Bakken, separate from the Three Forks.

Operator

Ladies and gentleman, I'd now like to hand the call back to Mr. Hamm. Please go ahead.

Harold Hamm

Thank you very much, and thanks for all the interest this morning and joining us. As they're saying in our business, the great oilfields keep getting better, and we're certainly seeing that with the Bakken, we have several instances throughout, and to a same instance, in the Woodford as we go forward. I would say that as we see the switch due to value, the switch on U.S. rigs from oil -- from natural gas to oil, we're approaching 60% of the rigs now working for oil compared to 15% earlier and seeing gas stand down to about -- looks like it's going to 40% or less of the working U.S. rigs domestically. Eventually, we should be affecting natural gas prices. Nothing stays the same forever. So I didn't say anything about natural gas prices earlier but certainly, down the road, we should see those change as we go forward. So thank you very much. We've enjoyed visiting with everybody this morning.

Operator

Thank you, ladies and gentlemen. That concludes your conference call for today. Thank you for joining us, and you may now disconnect.

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