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Executives

Harold G. Hamm - Executive Chairman, Chief Executive Officer and Member of Nominating & Corporate Governance Committee

Jack H. Stark - Senior Vice President of Exploration

Jeffery B. Hume - President and Chief Operating Officer

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

Analysts

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

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Joseph Patrick Magner - Macquarie Research

Jason A. Wangler - SunTrust Robinson Humphrey, Inc., Research Division

David W. Kistler - Simmons & Company International, Research Division

Continental Resources (CLR) Q4 2011 Earnings Call February 23, 2012 10:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Continental Resources Fourth Quarter 2011 Earnings Call. This conference call is being recorded.

Today's call will include projections, assumptions and guidance that all 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, followed by Jack Stark, Senior Vice President for Exploration, and Jeffery Hume, President and COO. After their remarks, 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.

Harold G. Hamm

Good morning, everyone. Thank you for joining us for Continental's fourth quarter earnings call. You probably heard me say that Hegler [ph] oil play has just keep getting better. That's certainly true with the Bakken. Again, there's only one Bakken, it's a world-class oil play, certainly without April [ph] in the United States in the last 50 years and it just keeps getting bigger and better and we'll talk about that some today.

I can say the same for Continental Resources. Last night, we reported record fourth quarter 2011 results. We entered 2012 with tremendous production growth momentum and EBITDAX growth momentum and the numbers say it all. We increased fourth quarter EBITDAX year-over-year by 86% to $412 million. Full year EBITDAX was $1.3 billion, a 61% increase. Production was 75,219 barrels of oil equivalent per day for the fourth quarter, 57% higher than the fourth quarter 2010, 72% of this production was crude oil.

In January 2012, we produced 84,200 barrels per day. Full year 2011 production was 43% higher than the total for 2010. Again, crude oil, not crude oil and liquids, just crude oil, was 73% of our 2011 production. If we reported combined liquids, that amount would be much higher due to our 1,500-plus Btu gas stream in the Bakken.

Mainly due to an unrealized mark-to-market loss on derivatives, we reported a net loss of $112 million or $0.62 per diluted share for fourth quarter 2011. Our clean net income of $0.88 per share for the fourth quarter when you back out the noncash derivatives loss, property impairment charge and a small gain on the sale of properties.

Clean net income of $0.88 per share is $0.11 above this pre-consensus number.

For the year, we reported net income of $429 million or $2.41 per diluted share. Again, the clean net income number would be $2.70 per share, $0.29 higher after back half noncash derivatives again, a gain on sale of assets and a property impairment charge. These are simply an outstanding operating and financial results.

Continental clearly has world-class asset positions in the Bakken and Anadarko Woodford and we're delivering world-class operating results to match. I can't tell you how proud I am of the entire Continental team of employees and the results they're achieving. As a result of their achievements yesterday, we revised 2012 production growth guidance to a higher range of 37% to 40% and this is without an increase in drilling capital expenditures. How is this possible? To simply put, and Jeff will expand on this later, our well results were stronger than expected in new expansion areas in the Bakken and in the Anadarko Woodford. When we developed our regional [ph] 2012 drilling plan, we've projected results on a risk basis in new and proven areas west of the North Cana in North Dakota, and the southernmost section of the Southeast Cana, the Oklahoma, Anadarko Woodford, and the oil wind of the Northwest Cana.

In these unproven areas it makes sense to send an explorer, for wells in these areas might not consistently match the productivity of wells across the play where we have extensive well control. Now we know.

These wells and the expansion areas are as strong or stronger than typical wells in established areas where we've done much more drilling. So based on approximately the same 2012 drilling investment and expected well count, we plan to grow production as much as 40% this year.

We're placed to an interesting question that would've been asked by more than 2 investors in recent months. How is Continental growing and operating at such a high level when other operations, especially in the Bakken, are challenged with several infrastructure constraints? And it's a great question.

First, Continental's focused on a world-class operation by a world-class team. We're committed to being the best, most efficient operator in the Bakken, Anadarko Woodford and oil plays. It starts with the people, we believe we have the most capable professional teams and they certainly have a great depth of experience, with older hands having operated in this place for decades. Certainly, we face challenges just like everybody else. And we've basically seen it all over the years and we've learned to anticipate future needs as drilling activity ramps up and as the infrastructure capacity is strained and when harsh weather conditions affect how we can operate.

With the benefit of our experience and talent, we're always planning ahead and anticipating challenges. Based on our drilling plan for instance, we know statistically how many wells will need servicing throughout the year and we plan accordingly to have work on the rigs available when we need them. Having such a large acreage position, we can move contractor rigs around as they are needed in different counties, like we did last year when some of the areas were still wet. Given our reputation and the fact that we have the largest drilling program and acreage position in the Bakken and Anadarko Woodford, we are drilling and service contractors lined up to work with us and men who are always wanting to lease with us to help us achieve mutual goals. They know we will be in the play for decades. We are the operator of choice and we work directly with midstream pipeline and railing companies so they are ready for Continental's growth as it continues to accelerate.

Sure, there are always pinch points and they constantly change that our team focus on managing those change -- changes as they evolve and that production growth and financial results reflect their success.

An interesting quarter to this today is how the teams are growing -- or move in Oklahoma City when the process will be finished in a few months has opened the floodgates of professionals who want to be a part of the Continental organization and what we're doing, especially in the Bakken and the Anadarko Woodford. We're adding people, especially young professionals, who will drive this company forward for many decades.

The second trait that sets Continental apart is that we're focused on just a few strategic assets, the Bakken. It is of course crude oil, and they have a leading position in this massive resource play and in an expanding acreage inventory we can drill for decades. And then the Anadarko Woodford, again, more crude oil and natural gas liquids and a leading -- and we have a leading position in a massive resource play again and expanding acreage inventory we can drill again for decades. As a premier exploration and development shop, we get in early the further geologic concept, and then we capitalize on technology advances to improve well economics as the play goes in large-scale development.

We're still growing our position in these plays. As you've seen from recent acquisitions, 35,000 net acres were stepped up in February right in the heart of the Bakken, and we expect further consolidation.

Third, our strategic focus carries over into how we operate and manage our balance sheet. We are a growth company but we're not going to over leverage ourselves.

We continued layering along the gas hedges so we can maintain our growth momentum and our capital program. We don't clutter up our financial structure with complicated arrangements that might hamper our ability to grow and create value year-after-year. We don't branch out into other business, we are pure and independent E&P operator and we're focused on oil and we keep it simple.

Finally, we're always looking for emerging opportunities and challenges. As we noted, we're running significantly ahead of a 5-year growth plan that we announced in October 2010. We're developing a new 5-year growth plan and a 10-year growth plan to share with investors our vision of Continental's bay creation potential based on our current assets over the next decade. We plan to announce our new growth plans no later than our 2012 Investors Day, which will be in Oklahoma City on October 9. We may have to roll out the plans in summer.

Next, we're preparing the chips and the full development node in the Bakken. We expect to have 12 to 14 ECO-Pad rigs drilling on multi-well size by year-end 2012. By year end 2013, we plan to have as many as 20 ECO-Pad rigs, at which time we will have our current acreage help our production and we'll be in full developmental mode. This will have a major positive impact on well economics, production growth and improved reserves growth. We're working with the vendors to assure that gathering systems, pipelines and rail facilities are ready for Continental operating at a much higher level in 2 years.

So we're always looking many years down the road for new opportunities with the quality of Continental's assets brought up to new opportunities emerge because of advances in drilling and completion technology. The latest game changer is the Three Forks lower ventures. We've literally found an additional oil saturated reservoir in the Bakken that again, makes this world-class oil play bigger and better.

I'd like to turn over the call to Jack Stark to give you a brief update on work with these lower Three Forks ventures. Jack?

Jack H. Stark

Thank you, Harold, and good morning, everyone. As you may recall, Continental acquired 6 cores of the entire Three Forks formation in 2011 and discovered they were up to 3 additional layers where benches of low bearing dolomite within the lower Three Forks formation. The significance of this discovery, and what makes us such a game changer, as Harold mentioned is, that the volume of oil in plays for the field, almost doubles with this added reservoirs.

Based on our estimates, the oil in plays now stands at around 900 billion barrels of oil versus our previous estimate of 577 billion barrels of oil. This in turn, should ultimately translate into more technically recoverable reserves for the field. Just how much more remains to be seen, but we have taken the first step to demonstrate through the bid that the second bench of the Three Forks is a commercial reservoir.

As you may recall, the Charlotte 2-22H was our first test of the second bench of the Three Forks, and it completed pooling 1,396 barrels of oil equivalent per day during its first 24-hour test. The Charlotte has produced a total of 45,000 barrels of oil equivalent since going online 3 months ago and is performing in line with a typical first bench producer.

Also reported last month, we participated in another segment test called the Sunline 11-1TF-2SH. The Sunline is located 20 miles east of the Charlotte and produce at a rate of 1,023 barrels of oil equivalent day in its initial 24-hour test.

During its first 55 days online, the Sunline has produced 34,000 barrels of oil, and like the Charlotte, it's performing in line with the typical first bench Three Forks producer.

During 2012, we will continue our pioneering work with the Three Forks reservoirs. We plan to drill 2 to 3 additional second bench tests and are also lining up our first test of the third or fourth bench that should spread around midyear. We also plan to cut additional strategic play scorers to further evaluate the Three Forks reservoirs.

We're using the core and metaphysical data to develop models with the help of a major service provider to better understand how we can contain fracs within a single zone or tie multiple zones together to modify fracture stimulation technology. So stay tuned as we continue to expand and extend in our understanding of this world-class oilfield.

Now I'll turn it over to Jeff for some additional highlights.

Jeffery B. Hume

Thanks, Jack. I'd like to mention just a few more highlights before we begin the Q&A.

First, let's talk about the wells we're drilling in the extension areas of the Bakken and Anadarko Woodford and the increase in production guidance. As Harold noted, we increased 2012 production guidance to the range of 37% to 40% growth, with no increase in CapEx, let's walk through the process.

In the past 6 months, we've been drilling in a Bakken extension area west of the Anadarko in North Dakota and in Anadarko Woodford where we are working further south in the Southeast Cana and the northern Blaine County in the Northeast Cana where we are in the oil window.

Because we had so little well history in these extension areas, it makes sense to apply a risk factor or to discount initial production expectations for wells to be drilled in and out. Until we have actual results which helps to tune our model.

After completion -- completing numerous wells in these areas, we determined that derisking was unnecessary, because the extension wells were just as strong as those in our established areas in the Bakken and Anadarko Woodford. Therefore, we trued up our production model for 2012. That's a significant amount of new production with the same number of wells without any new CapEx. Obviously, it moved the needle on 2012 production growth.

If that didn't sufficiently clarify our modeling process, I'll be glad to answer questions about it in a minute.

Now let's look forward to our 2012 and 2013 operations.

First, the Bakken. In the next 24 months, you will see us transition from drilling mainly single wells to drilling mainly ECO-Pad projects, 4 or more wells per pad. These -- the key here is that we expect to have almost all of our Bakken property held by production by late 2013. We currently have 7 ECO-Pad capable rigs drilling, these are hydraulic walking rigs in the play but only 3 of them are drilling ECO-Pads at this time. The rest will transition to ECO-Pad drilling by year-end 2012 and in that time, we will also add more ECO-Pad rigs ending the year with 12 to 14 in a fleet

By year-end 2013, we expect to have as many as 20 ECO-Pad rigs in operation, drilling our multiple well pads. By then, we will be in full development mode in the play basically running a manufacturing operation. In addition to the cost efficiencies we've already seen, this level of ECO-Pad drilling will present new opportunities.

One concept that we're working on is drilling a string of adjacent stacked 1280-acre spacing units. Think of 3 1280 per spacing unit side-by-side by side with 3 more stacked on the top of them. Three north units share a common with the 3 south units. And we've put one ECO-Pad rig on the west edge of that boundary so we can drill 2 Wells north and 2 wells south in the first pair of spacing units. When it's finished with those 4 Wells, we move the rig a quarter of a mile east to the next pad and do it again. We keep repeating that pattern over a distance of 3 miles until all 6 spacing units are drilled. This will be an incredibly efficient way to drill 48 wells and 6 spacing units with minimal rig moves and a concentration of completion services in a relatively typically small area. We will also minimize the surface impact on the land.

Anyway, that's one concept we're working on in the Bakken in terms of drilling to make our operations even more efficient over the next few years. Next, let's talk about field gathering and transportation infrastructure in the Bakken.

Significant process has been made in the last 4 months getting gas gathering lines, new processing facilities, a total of 160 million cubic feet of new plant capacity opened up in January and water and oil gathering lines of built in the field. Along with improving operating efficiency, this gets the trucks off the road, which is a clear priority in North Dakota. Everyone, including local communities benefit from this.

In terms of long-distance transport, we are increasingly relying on rail to deliver oil to the Gulf, East and West Coast, where our Bakken oil competes with waterborne barrels.

Today, roughly 1/2 of our Bakken oil is railed and most of that goes to the Gulf Coast where it is processed relative to Louisiana Light Sweet.

A quarter of our Bakken oil is [indiscernible] Minnesota and 1/4 goes to Guernsey, Wyoming. That's the split on our Bakken barrels. The paths are fold so obviously all future production growth will be shipped by rail. Our Red River unit, oil is pathed to Guernsey. We're moving all of our barrels out of the basin today, without a problem where we're also constructing additional storage capacity for our protection for capacity disruptions in the future. For any investors who are new to our story, Continental is different from some operators in that they would mark their own core, and we have very good communication with our refinery customers. So in early February, we were not as negatively affected by the differential blowout than some of our peers.

Finally, before closing, let me add a few observations about the Anadarko Woodford. Our Woodford team has done an excellent job to shift drilling rigs into oil and high liquids areas where they can generate returns that are competitive with the Bakken. Within 3 months, our 10 operating rigs in the Anadarko Woodford will be concentrated with 8 rigs in the Southeast Cana and the other 2 in the Northwest Cana, drilling an oil window in northern Blaine and Dewey Counties.

In the Southeast Cana, we've announced 3 wells: the Lambakis, the Lyle and the [indiscernible] that are excellent wells with strong oil and high liquids gas production. We've leased about 25,000 net acres in the area where these 3 wells are located, and we're drilling a very thick Woodford zone here, about 250 feet thick. It's an excellent area with a great deal of production growth potential with high-value wells.

In the Northwest Cana, we completed our Toms 1-21-XH well, the first Cushing well drilled in Oklahoma and the results we're outstanding, as we announced last night. It filled 1,268 barrels of oil equivalent per day in the initial 1-day test and 7 -- or 6% of that was oil. The Toms is a 9,500-foot lateral that was completed in 26 stages. We're already drilling additional Cushing at wells and look forward to discussing them on future calls.

Hope that gives you a better idea of where we're headed over the next year or 2. I'll close by pointing out a few things that apply to our overall operating strategy.

First, we're focused on oil and high liquids opportunities in the Bakken and the Anadarko Woodford where we generate superior returns. Second, we're focused on expanding our strategic footprint in these premier plays. And third, we're intently focused on the transition to ECO-Pad drilling and other opportunities to improve our efficiency, and therefore, the cash margins for our operations.

With that, let's start the Q&A period.

Question-and-Answer Session

Operator

[Operator Instructions] We do have your first question from Noel Parks of Ladenburg Thalmann.

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

I got on a little late. Did you talk about the Bakken acquisition that you did and just a little bit about how that came about and the timing? And also, I was wondering what the proved reserves amount acquired wasn't, and how many wells make up the 1,000-barrel a day’s production?

Jeffery B. Hume

The package that we bought was publicly marketed and we participated in that and we're the successful bidder in that. We don't name companies that we buy from, that's just a policy that we do. The production came from predominantly established wells. Most of that acreage was held by production. I don't have a real accurate count on top of my head, but I think it was in the 40 to 60 range.

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

Okay, great. And as far as that acquisition, was it properties or a company acquisition? I was wondering if you took on any debt from the seller.

Jeffery B. Hume

It was property acquisition.

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

Okay, great. And just on the Cana Woodford, could you talk a bit more about your thoughts on some of the oil content in the northwest versus the southeast? I realized the big Tom's well was a dual lateral, that it was a lateral area -- but for the southeast where you drilled, it actually was a little bit less oily than I was thinking, I think it was the one to the far south part of the area, so can you just update us on that?

Jeffery B. Hume

Sure Noel. In the Northwest Cana, as we move to the north and northeast, along there is -- mainland and northern Blaine County, we're just seeing excellent results. The first well that we drilled in there was the Petty, and we followed it with the Toms well, where significant acreage block in that area, we just have -- we're just getting farther up depth into that oil window and have, obviously, enough permeability to produce it in that area. So that's very good news. To the Southeast, we're still on that gas condensate window and moving to the up dip area, we'll probably see more oil. To the north, in, say Central Grady County, around Chickasha, Oklahoma, we've drilled a couple of wells that are very, very strong oil wells and have a higher content. One thing I'll point out though is, all the gas in that area is over 1,300 Btu, so it is very high on liquids that we're getting plus what we're recording, which is well ahead oil and condensate.

Operator

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

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

On the Toms again, how much was it? And what do you think a development of the cross unit might look like? And sort of a what -- first-month production would make you have a 30-day rate? And when you look at the pressures and choke how those compares to, say, a typical Bakken completion?

Jeffery B. Hume

I would say on the 30-day rate, we're looking at, on average of about 600 barrels a day and about 2.5 million cubic feet a day, and that is a rich gas up there in that oil window too, and about the 1,300 Btu, so we're really excited about that. Actually, you're going to see a little higher, still a little bit higher GOR in -- than most of the core Bakken areas, we do see some of the Bakken areas have higher GOR, so it's not going to be radically different than the Bakken, to be honest with you.

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

Okay. And the well cost?

Jeffery B. Hume

Well cost on the Toms was $12 million. Remember, this is a 26-stage job and so it's -- it is a little higher than we've seen in a Bakken. But bear in mind, this is our first one done in the state. And actually, the drilling time was -- compared to a Bakken well is longer, we were 38 days, which are still past our expectations by about 11 days, so I'm really excited about that.

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

Right. Is that just hard rock country?

Jeffery B. Hume

Much harder drilling than for the Bakken. Yes, sir.

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

Okay. And so in the Bakken, any update on well cost? And, curious as you sort of go into outright ECO-Pad drilling, what you might see in terms of spud-to-sales and average Bakken well costs?

Jeffery B. Hume

So -- we're still in that average of around $8.2 million, we're running on the low side of $6.9 million to a high of around $9.8 million, depending on where we're at in the play, the hydraulic horsepower required to frac the wells and the drilling time. So that's kind of the range, but we're still in that $8.2 million range. We're seeing prices stabilize pretty well, we still have some upward pressure in some items. We're seeing some downward pressure in others but right now, we're seeing it pretty well-stabilized right in there, and we feel like we could continue with that. The ECO-Pad wells have been giving us a true 10% cost reduction. We think we can expand on that in the future as we go into the development that I described earlier, because obviously, we can put pipelines in there to deliver water and remove frac water from herein, not have to truck that, and some other efficiencies that we'll gain when we can do that. The time to drill, we've -- we have drilled these wells, a 4-well pad, in the 85 to 110-day range. So following that, we're looking at -- or we can immediately start frac-ing because these well packers on the initial wells drilled were set, so it's just a matter of days of getting the rig off, planning the location up, getting the frac equipment in, we began frac-ing. Then we'll sit there for at least 2 weeks of frac-ing, doing that followed by a couple of weeks of cleanup and putting the wells on. So altogether, you're looking at 120 to 160 days of from when you start or when you have all the wells producing.

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

Okay. And the transportation cost, Jeff, is all of that netted against your realizations?

Jeffery B. Hume

It is. Our net that we show is at the wellhead net of everything, so it includes trucking or piping from the wellhead to the nearest rail or regional pipeline terminal, then deposit it to a market -- get it to our market, and then the discount that we take at the market or our bonus that we get at the market.

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

So the -- given your rapid growth, I guess the marginal supply going to rail, could you further split what you think the rail takeaway might look like this year? How much of it goes to Gulf coast versus other ports of call?

Jeffery B. Hume

Well, we don't have -- we're not -- don't have a forecast on that. We're contracted with various shipping suppliers, rail supplies and we're going to various markets and there is flexibility in that. And as we grow, we're going to continue to find the best markets we can. That's it. I guess the one upside of rail capacity is, one, it can quickly grow to meet your needs and it can go to the market that brings the highest price. So it's a -- we work that every month, we maximize value to the wellhead, from finding the best markets and getting in to those markets.

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

Okay. And then one final one for me. So in these acquisitions, and I think I've always seen you guys as extremely deliberate and disciplined in making deals. I was curious if -- if it's -- what sort of advantage you now bring to the table in bidding for these packages versus the competitor? I mean is it just that you have these seamless operations, and sort of how, or if you are looking at these acquisitions differently?

Jeffery B. Hume

No, these are -- everything we've done is a strategic acquisition. It adds Bakken acreage to an area where we are the lowest cost developer of that. And I believe that puts us in a unique position to -- we're involved with every opportunity out there. We don't obtain every package that's out there but we do compete on those. And so the Bakken's in consolidation mode and you're going to see just a few operators end up controlling the Bakken. And I think we've set ourselves above everyone else on being able to control and handle it. And even in times right now, we're hearing a lot of other operators having difficulties. We're having the same difficulties, we're just way ahead of them on planning and we're going to try to continue with that. And I'm not going to tell you there's not pinch points, it's tough out there. It's tough to do but we manage it, we take great pride in that. We've got the people and I think that's the key thing. We've got the people with the get-it-done attitude and they go for it.

Operator

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Can you talk about the improvement of productivity from the step up [ph] Bakken wells? And can we assume that, kind of an overall Bakken EUR is going to move higher?

Jeffery B. Hume

Well, I wouldn't say that yet. What we have -- we built our models based on our various areas, we provide the market with an average across those areas and that's currently 603 in Boe. We're staying with at this time. You'll recall that in August, we announced that we're going to 30 stages our base and -- 30-stage fracs at our base. It took a few months to get some of those wells in place. We've frac-ed several of those now, they're coming on. We're seeing real strong IPs on those. As you would expect, we got more stages. We're going to be looking at that and see how the curves line out. And probably midsummer, we'll be reviewing where we're at on the overall model. Now the expansion areas, as I've described before, we took that model and put a risking factor on it because they were unknown. We didn't know if they're going to be in the 500,000 range or the 700,000 range. We didn't know how it's going to be. And what they're proving out to be is they're falling in the line with what we have throughout the rest of the area. So area up and down the anacline is -- looks very similar to what we're finding now at west of the anacline. And so what we call our Williston Prospect going up to the Montana State line, both in Mackenzie and Williams County. So we're seeing a good area there that's increasing in productivity. And as we continue to work with frac technology and completion technology, which is -- we're still in the early innings of that. And as we get to where we're drilling more densely in one area, we'll be able to do more tuning of that because right now, it's kind of a standard design that we're applying almost everywhere. But once we start developing in the various areas of the field, we'll be able to tune for that area.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. That's helpful. And Jack mentioned this earlier, but how has that second -- the weather showed in the second bench of the Three Forks? How long has that been online? And I'm assuming it's a similar EUR as your average Bakken well? Is that accurate?

Jack H. Stark

Yes, Brian. It's really been great, we -- it's been on for 3 months and as I said, it's produced about 45,000 barrels of oil equivalent and it's just lining up very nicely, we're very pleased with it. And the Sunline well, which has been on for about 55 days, is actually outperforming the Charlotte wells. So we have 2 very good producers, and the key thing there is that not only do we have 2 producers, but these are 20 miles apart. And so these are the first 2 tests in that basin, they are 20 miles apart. And to get that kind of repeatability over a 20-mile stretch is pretty impressive. So we're really encouraged with what we've got there and think of those very well for the second batch.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then one final question. I mean, obviously, production has been extremely strong. And how do you look at managing your capital spend and kind of managing that production growth, kind of on a corporate level? Because it seems like the growth could be much, much higher just all depending on the CapEx, and -- how do you all look at that?

Jeffery B. Hume

Well, we try to keep our debt metrics in line, as Harold stated, and we'll continue to do that. But as we grow, our base grows, we'll be able to lean in into our borrowings. There's many other things we can do. There's assets that we can sell that are mature now, we'll be looking at that, there's a potential for us to be doing. So there's many opportunities to do that. What we're seeing right now, we're very concentrated on improving our performance and improving the turnaround of our dollars in these current properties. And running it about ideal rate for the infrastructure that we have in place right now, we'll be able to, I believe, really accelerate this starting in 2013. As we go to the ECO-Pad development end in the Bakken, we're going to be able to get more wells done with fewer dollars and we're going to be accelerating just through that process and we'd be able to add rigs more than likely because of that without getting out of our alignment. So it's that balance that we have with discipline -- of disciplining our spend with what we do. An example of that is what we did with our Anadarko team. We set them down in the last -- in the fourth quarter last year, just about when did our budget and decided, those dollars probably need to go somewhere else if we continue to be in that gas area of Anadarko Woodford. That team answered the call, the testing that they've been doing in the Southeast Cana and that one on the north -- northern edge of the Northwest Cana, proved that we have enough oil in the system to keep the rigs there, to compete with the rates of return that we're seeing in the Bakken. And so we've transitioned to that very rapidly to do that, so we're very cognizant of putting our dollars where the highest rate of return depending on the commodity price and the cost of development at that time, and we'll continue with that.

Operator

Your next question comes from the line of Joe Magner from Macquarie Capital.

Joseph Patrick Magner - Macquarie Research

Just wanted to -- I appreciate the color on the improvement in the well performance in the new areas and how that's affected the outlook for 2012 growth. How do we think about -- there was a quite a bit of spending in the fourth quarter last year, a little over $800 million and only a $1.75 billion budget for '12. Were there any items that affected the fourth quarter spend rate that we should expect to not see going forward? Or I guess can you just kind of walk us through what might have…

Jeffery B. Hume

Yes, absolutely. If you recall, we added extra rigs in the Anadarko. And we had a huge inventory of wells to be completed in the Anadarko Woodford, larger than normal. And so we came in to the fourth quarter and we're going to come in to the first quarter fairly hot on completions in the Anadarko Woodford. Five of those rigs are going away where I think 3 of those have already been released. We'll have 2 more leaving fairly soon. And so that took that CapEx up higher. The other thing is we were building lots of locations for the winter operation, and all those dollars show up, both of those show up in the fourth quarter because we really go after building locations in October, November and early December before the frost hits in the ground. So we front end load quite a bit for the next year and done that. In addition to that, we had some acquisitions that we paid for during that period also, so that all put into there. So those 3 items will not be repeating after we get out of the, say, into the second quarter with a recap coming down, and completions will be less, and that will line it back out. So it's all attuned in there.

Joseph Patrick Magner - Macquarie Research

So it sounds like the first quarter might be running higher than the annualized rate then we'll start seeing it level out the second, third and fourth?

Jeffery B. Hume

Well we expect it to continue to grow some but right now, we are rotating some rigs out of Bakken. We're currently down to 22 for a few weeks here and reason for that is we've got some refurbished rigs that, with walking mechanisms that will be coming out within the next couple of weeks. And the last rig, will -- we released a couple of rigs here in the last few weeks to go in to be refurbished. So part of the rig upgrade and modification to walking rigs is going to probably slow down our Bakken completions a little bit into the second quarter just due to the -- don't have the number of rigs running, but then it will pick back up and accelerate again into the second quarter, or actually in the third quarter completions.

Joseph Patrick Magner - Macquarie Research

Okay. And one other thing I wanted to clarify, it sounds tells '13 is probably the period of time where we'll start to see an acceleration. But I think in the past you've made some comments that as long as oil prices were above 95, you would consider perhaps increasing CapEx. Is that still possible for this year, or?

Jeffery B. Hume

No, certainly. What we'll do every year is, midyear, we'll review for commodity prices we're at, where we're running on spend rates, see where the market's at. And if we can keep ourselves in line with cash flow and accelerate, we'll readily do that, and we have -- that's the beauty of it, we've got the inventory to do it and manpower in place to do that. So we'll make that decision in midyear and if there's a very good possibility on that. But back to your point on accelerating, I mean, we're going to have 40% growth this year, what are we expecting?

Joseph Patrick Magner - Macquarie Research

No, certainly that's a very stout growth rate. I guess it was based off better productivity of wells, and account that hasn't changed.

Jeffery B. Hume

Certainly. No -- but I think we can maintain very high growth rates out in the future with what -- with the cash flow we have available and continue to accelerate. With the efficiencies we think we'll gain as we go to ECO-Pad drilling the second half of this year and into 2013, I think we'll really be able to maintain that. And as you know, the larger we get, the harder it is to have -- maintain that growth rate. But we feel that we can do it with our inventory.

Joseph Patrick Magner - Macquarie Research

Okay. Care to identify which non-core assets could be lined up for sale at this point?

Jeffery B. Hume

No. We've got several of them and we don't have any particular in mind.

Joseph Patrick Magner - Macquarie Research

Okay. And then I guess looking out with incremental barrels targeting access to increasing rail, you mentioned that some of those agreements were locked up on a long term -- what sort of visibility do you have on access to the rail?

Jeffery B. Hume

Rail access? Well we work with -- as I said, we work with several rail transportation companies and we're working with several markets at the other end. And we have in place, capacity for the future. And as we grow our production, we tune that as we go, obviously. We build models of what we think we'll be producing and then as well performance and operational performance dictate, we'll either sell that down or speed that up. Right now, we have adequate capacity in front of us, we have some that are short-term contracts and orders that are longer-term, it's a mix.

Joseph Patrick Magner - Macquarie Research

And I guess, just -- others have commented on perhaps some challenges on having access to the rail cars and maybe some loading and unloading facilities that are not running at optimum rates, you've talked during your comments that you're ahead of others in the industry, but just kind of how do you see the market right now? And how could some of these recent challenges get worked through over the next couple of months?

Jeffery B. Hume

Well, we just see more facility. When we have everything covered now, we have our future growth well-covered on both ends, on the loading and unloading and rail cars. We see additional capacity coming on, we have people coming in to see us every week that we have been thought about that has capacity and are building facilities to unload at the other end. So I think there's going to be more than adequate rail capacity to handle what we're doing. We -- right now, we've got everything in place that we need for our current projection and then we work to tune that up and down as production ebbs and flows. But right now, we're running ahead of schedule, and we've added some colors for that and we're on top of that. We're also, as I mentioned building some storage tanks in the field to take care of any interruptions that might occur. We've got tankage that we are building ourselves that are along both a combination of the rail line and regional pipelines, and we're also working with vendors that have storage on the rail side. So we're going to have, we feel, uninterrupted flow to the market through both pipe and rail as we continue to grow production in the Bakken.

Operator

Your next question comes from the line of Jason Wangler from SunTrust.

Jason A. Wangler - SunTrust Robinson Humphrey, Inc., Research Division

You may have answered this already, Jeff, a little bit, but just wanted to be clear, you've got the 7 rigs that can walk for your ECO-Pads, now, you want to get to -- I think you said 12 or 13 by year end. Will be adding those rigs or will you be refurbing them? Or are you just switching those out? Just trying to get a sense of where the rig count's moving as we go throughout the year?

Jeffery B. Hume

Well, we'll be doing both. We've released a couple of rigs that were poor performers and we've replaced those with some walking rigs, so we're bringing in some new ones and we'll also do in the rotations. So the answer to your question is, we're doing both. We're going to have, on average of a 24-rig program, we'll get as low as 22, where we're at now, we'll probably get a high for a while at 26, maybe 27 rigs. But on average, we're going to hit a 24-rig average for the year.

Operator

Your next question comes from the line of Dave Kistler with Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Real quickly in the Cana Woodford, given the liquids cut there, can you talk about processing capacity and how you're handling that? If you mentioned it earlier, I apologize.

Jeffery B. Hume

No, we have not discussed that. We are working, with -- right now, in Northwest Cana, we've contracted with one large entity that has plenty of processing capacity and very strong market. In the Southeast Cana, we head out to bid at this time, for the gas process in that area, knowing that we're accelerating there, we'll be letting that bid in the next few weeks. All of the participants in that are going -- have plenty of processing capacity in place and the ability to drill into it faster than we're going to be developing our product. They have very strong pricing. Bulk of that production is going to have Bellevue pricing on it. Pipelines will be opening up within 1 year or so to get more product to the Gulf Coast and we feel very, very good about what we're doing there.

David W. Kistler - Simmons & Company International, Research Division

Okay. That's helpful. And then, looking at your 40% production growth, how should we think about that mix? Is that going to remain kind in the same that it has been? Is there any kind of shift to that?

Jeffery B. Hume

No, it's like the mix -- it'd probably be a little bit heavier on the oil because of moving the rigs in Anadarko. We had quite a bit of gas come on and -- from the Northwest Cana this past year. With Bakken, we're going to be about the same growth there. We had -- we actually had a little bit of gas production come on January, February, from being constrained on processing in the Bakken but that's in the mix now. So I think overall the mix will be leaning a little bit more towards the oil side. And we don't tally up NGLs. We show it as gas so it's billow oil or forest crude oil. And probably a little richer on the NGL where we're drilling.

David W. Kistler - Simmons & Company International, Research Division

And then, just one more if I might, it's a little bit more micro. When we look at the Bakken, can you talk about relative to the number of wells, what percent of those you're tying to gas end versus flaring, things like that?

Jeffery B. Hume

I don't have a count right now, but there's very few wells flaring today. And those are mainly in those extension areas where we don’t have pipeline capacity built yet, but they are building it. That's one thing that's we've been blessed with this winter, we have not had a hard winter in North Dakota, so the infrastructure buildout is really going well. We have a few areas that they are just having some difficulty getting to from topography but that is being worked out and we're getting there. But whenever you do an expansion of an area with these wells, first thing you have to do is one, prove that you're going to have adequate production to justify that larger pipes and then get the pipes built. In all of these areas we are underway, we've got our supply, or our process and our midstream companies are laying those lines now or have plans to lay those. So we have very few wells that are flaring and on wells that are flaring, we slow down their production and we hold it back. And so once we get the well cleaned up and some of the frac layered off, we'll slow those wells down and minimize that. So we're managing that very well. And I feel a bit like by next year this time, every well that we drill in North Dakota will immediately be selling gas.

Operator

Your next question comes from the line of Jeff Wylin [ph] from Private Investors.

Unknown Shareholder

I'm a private investor and I have a significant amount of my personal walk in your company and I appreciate the opportunity. But on a day-to-day basis, what would you guys say is your largest risk that you guys talk about?

Jeffery B. Hume

Our largest risk?

Unknown Shareholder

Yes, largest risk for this company.

Jeffery B. Hume

Well that's probably the thing we can't control, that's commodity price. Everything else, we control. We've been controlling it for years and so we concentrate on what we can do. But we underpin that commodity price with hedging. And we have a very, very good hedging program that underpins that. So we don't see anything out there that can be real significant. Outside of just wild government regulation coming out of the blue, I don't see anything that big.

Unknown Shareholder

Okay. I'll ask about that. In the Bloomberg article, [indiscernible] it indicated that his relationship when he met the President was a bit generous at best probably, I'm just wondering like going forward, if you guys continue to have discussions with people in Washington how that relationship goes or if it -- or if there is a relationship?

Harold G. Hamm

Well, we have an excellent relationship in Washington. And it's very positive and a lot of focus there. We know exactly where we need to go with domestic energy production, and the gains that we've made and very thankful for that. And obviously the administration so far, hadn't done anything, hadn't been able to do anything real honest to the industry and that's good. So we hope that continues.

Operator

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

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

On the -- Jeff, the backlog issue, Anadarko Woodford, so that was in your 10-net row completion number?

Jeffery B. Hume

Right. That will be the cost. We have all those wells that we're drilling that we're coming out of completion, so you're paying for all of that drilling, those 15 rigs in the Anadarko Woodford and we have one in the Arkoma Woodford, I didn't mention, that's also left the mix. So we had all of that, there was drilling wells and completing wells in the fourth quarter that we'll work out through the first quarter, but with all the completions will hit this quarter, and then we'll work that down.

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

Okay. What is the current backlog, then? And then -- do the same thing apply in the Bakken? Was there a substantial backlog and is that being worked out?

Jack H. Stark

No, I think the backlog right now in the Anadarko Woodford, we currently have approximately 10 Wells waiting to be completed. And that number will be coming down gradually. I think normally, you're always going to have with the 10-rig program, you're always going to have, a half dozen-or-so, 5 or 6 wells waiting to be completed. Up in the Bakken, that number is probably on the average, going to be in the 30, plus or minus 30 to 40 wells. At some stage you're waiting on completion, waiting on to being to be run in the oil cleaned out, that sort of thing. So right now, in both of those plays, we're pretty much -- our backlog is pretty much what you'd expect on an ongoing basis, maybe slightly elevated here. As Jeff mentioned in the Woodford, because we've gone from 15 rigs down to our target of 10.

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

Okay. Got it. Okay, so, yes, I guess what I'm trying to understand I guess is, backlog is probably not the right word for the Woodford since you'll always have just about as many wells as you have rigs sort of more or less, waiting on completions. So it's basically the change from 15 rigs to 10 rigs that reduces your quarterly run rate on CapEx? I mean that's probably more so than the backlog issue, is that?

Jeffery B. Hume

That is correct. Just what happened, we picked up the additional rigs about midyear and so it takes several months to build, to get some wells drilled for completion and in that completion lags the drilling dollars, and then we released those rigs around the first of the year. And so we're going to have -- so fourth quarter, we have both drilling and completion of that higher account, that is going away now. We'll have completions carry over into the first quarter and then we'll be at a lower run rate for second, third and fourth quarter in those areas.

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

Okay. Okay. That's a much better understanding of it. And finally, your -- sort of your legacy stuff. What are your latest thoughts on what you think between areas outside of Cana and Bakken can do in 2012? Go up, go down, stay flat?

John D. Hart

Well, we're seeing the Cedar Hills is actually growing. The Red River units have grown and that's just a testament to our people and what they're doing and how they're performing. We have -- we're under water flood with the Cedar Hills unit proper, it's got potential for tertiary recovery. We're studying that, we're not announcing anything on that, but that's a future opportunity we have there. We have secondary recovery potential on the Bakken. If you just go look at the Cedar Hills, we drilled those first wells in 1995 and so that was 17 years ago. It's at its peak today and we've said that for about 10 years, it's at this peak today and it just keeps growing because we find that we can drill at a tighter density, we can waterflood, we can tertiary recovery, we keep doing that. The Bakken is going to prove out to be the same thing and we're not alone out there. Other operators are announcing that yes, that they're going to run on secondary recovery, possibly tertiary recovery in the Bakken in certain areas where that maybe. In other areas, like the Niobrara, we haven't talked about that much, but Niobrara, we've identified an oil window. We have one rig working in there, we're getting better results, we're climbing that learning curve that we always have to climb in a new play. We think we have a 25,000 to 30,000 acres in -- within the oil window to develop. And that's going to be growing, and we didn't talk about that much. We have one rig in there, we can quickly accelerate that once we feel comfortable with that play and some of the delineation work we're doing right now.

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

Okay. And when you look at sort of the other things, like Cana being probably the more significant plays, other mid-continent, Gulf coast, or the Rockies, any specific view on those properties?

Jeffery B. Hume

I think they're going to be pretty well flat without a little loss. We don't have much on the Gulf coast, and we go down there ever year and grow 1, maybe 2 wells, and we maintain that flat but it's real small proportion. Our eastern division maintains a flat production, they replace our reserves very readily there, that's mostly shallower oil or water clubs, we've got a great play going in Michigan up there on that, we've got our gas line in place there now so we're able to do some more drilling which we'll probably be doing this summer. And so we're in a position to grow those oil areas. Also, the others -- Rockies is very flat, very stable oil production and without a lot of movement, it's probably in the 3% or 4% decline type of its line. So it's very stable and that's what it looks like. So that's one of the advantages we have. We've got a real strong base with low decline that we're building on.

Operator

Thank you for your question, I'd like now I'd like to turn the call over to Mr. Hamm.

Harold G. Hamm

Well, thanks again, for joining us today on our fourth quarter conference call everyone. We delivered exceptional results and we're poised for even better results in 2012 and 2013. We're aware and appreciate that Continental plays at a premium valuation compared to almost all of its peers as it should, because of the plays we're in. I hope we've demonstrated, with our performance, that, that premium is certainly justified and in fact, we have a lot more growth we’d like [ph] to deliver for many, many years, it just keeps getting better. Please mark your calendars for our 2012 Investor Day, which will be here in Oklahoma City on October 9, if you haven't reserved the date already. We'll be disseminating details on the event very soon, and we hope you will join us for a very informative day. Thanks, again, everyone.

Operator

Thank you, ladies and gentlemen. That concludes your conference call for today. You may now disconnect. Thank you, for joining. Have a very good day.

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