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Executives

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

Winston Frederick Bott - President and Chief Operating Officer

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

J. Warren Henry - Vice President of Investor Relations

Jeffery B. Hume - Vice Chairman of Strategic Growth Initiatives

Jack H. Stark - Senior Vice President of Exploration

Analysts

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

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

Abhishek Sinha - BofA Merrill Lynch, Research Division

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

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

Yiktat Fung - Jefferies & Company, Inc., Research Division

Paul Grigel - Macquarie Research

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

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Continental Resources (CLR) Q3 2012 Earnings Call November 8, 2012 10:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Continental Resources Third Quarter 2012 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; followed by President and COO, Rick Bott; and Chief Financial Officer, John Hart. After their remarks, we will have a question-and-answer session period. Other members of management are available to answer your questions.

Now I will turn the call over to Mr. Hamm.

Harold G. Hamm

Thank you, Lisa. Good morning, and thank you for joining us for Continental's Third Quarter Earnings Call. This morning, we'll shorten our remarks as most of you joined us here in Oklahoma City for our October 2012 Investor Day, where we provided a thorough update of our operations and our growth plans for the future.

On this call, we’ll review our recent results and growth strategy, focus on how we expect to create growth for shareholders by achieving our growth plans in a cost-effective manner. And for those of you that's been affected by the storm -- recent storm and the current storm Sandy and the Northeaster, we sympathize with you.

We're pleased with Continental's Investor Day. More than 600 investors joined us here and analysts participated in person. We filed the presentations on our website. We appreciate that opportunity to share our vision for the next stage of Continental's industry leading growth and provide some color on the SCOOP play in Southern Oklahoma. We have dynamic and exciting plans for the next 5 to 10 years, focused on enhancing profit margins and maximizing shareholder value.

As we announced, we once again plan to triple Continental's production and proved reserves by year-end 2017, positioning the company of the next super-independent in E&P. Our recent results certainly point toward achieving that goal.

For the third quarter, we achieved record production of 103,000 Boepd and exited to the quarter in September with average production of 106,000 Boepd. Third quarter production was 55% higher than the same quarter last year and, sequentially, was 9% above the second quarter of 2012. We are finally on track to achieve our growth guidance for 2012, a production increase of 57% to 59% relative to 2011. We look forward to finishing 2012 with strong fourth quarter production and carrying that momentum into the new year.

So let's take a look at 2013. We expect production to increase in the range of 30% to 35%, a strong start for our new 5-year growth plan. A key point to stress here is that we have the assets in hand to achieve not only our growth plan for 2013, but also our growth plan for the next 5 to 10 years. We've got leading acreage positions in 2 premier oil and liquids-rich plays, the Bakken and SCOOP in Southern Oklahoma, which are cornerstone assets for a next decade of growth, and we are adding to both of those positions.

As you saw in our announcements yesterday evening, we have entered into an agreement to purchase an additional 120,000 net acres in the Bakken, which will take our current position of 984,040 acres -- net acres to more than 1.1 million. In addition, we've increased our SCOOP position to 197,340 net acres.

To further support our growth strategy, we are strengthening the company's organization to manage operations cost effectively on a much larger scale. Along with young bright engineers and geologists, we're bringing in seasoned professionals with decades of experience in large drilling programs and other key processes. A critical area of emphasis is our oil and gas marketing group, which is focused on developing new opportunities to meet and market Bakken oil to refineries and other markets on the East, West and Gulf Coast, creating a quality market for Bakken oil.

Additional pipe and rail infrastructure has broken the logjam of Bakken oil, and we are marketing our barrels directly to refineries on all 3 coasts, as well as in Canada. This has resulted in reduced oil price differentials that you saw in the third quarter, and John Hart will expand on this later.

Finally at our Investor's Day, we discussed an interesting contrast in Continental's operating strategy, the fact that we are capturing the capital and operating efficiencies of large scale development while still exploring and expanding the scope of our key plays. Rick will expand on this further. But the key point is that while we continue to assess new opportunities in the Bakken and SCOOP, we're reducing cycle times and realizing efficiencies in both drilling and completion.

This speaks to our focus on value creation. Continental has an unparalleled opportunity to create value through strong growth and enhance capital efficiency. We are positioned for another year of excellent results in 2013, with strong production growth, further addition in proved reserves and increased profitability.

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

Winston Frederick Bott

Thank you, Harold. I'll start with earnings. EBITDAX for the third quarter was $492 million, 46% above the third quarter of last year and 17% above the second quarter of 2012. Capital expenditures were $727 million for the quarter, which is exactly on target to meet our goal of $3 billion in non-acquisition CapEx for this year.

As Harold noted, let's look at several third quarter operating trends that will help us grow production more cost efficiently in 2013 and continue to build cash flow. Firstly, we are starting to see increased availability of drilling and completion equipment and crews in the Bakken. The supply of services and equipment is starting to come into -- come in line with demand. We also see this in ancillary support services like construction spreads, rental equipment, et cetera.

Our trademark industry-leading ECO-Pad concept has really become a standard drilling approach in the industry because it improves land use, as well as operating efficiencies. We started with 4 wells per pad but as you've seen, we've now designed larger and larger multi-well projects, with up to 14 wells on the site.

Throughout this year, we talked about the transition to pad drilling. In the first quarter, 10% of our operated fleet was on multi-well pads. Today, 45% of our operated rigs are engaged in pad drilling, and that percentage will continue to grow. This mirrors a higher number of rigs drilling in field projects. In other words, development in spacing units already held with an additional well. So these rigs are drilling second to third wells in that spacing unit.

And how does this contribute to lower cost per well? Firstly, we save on access and site construction costs by using and extending existing roads and augmenting infrastructure that we constructed for the additional well in that spacing unit. Incremental site construction costs for additional wells on an existing pad are much lower.

Secondly, pad drilling minimizes rig moves. However, when we do move rigs, the average cost per rig move has also been reduced 17% this year. As we've discussed in the past, pad drilling helps reduce drilling cycle times. Currently, we're saving 10% per well on ECO-Pad projects, reflecting this acceleration, as well as leveraging this infrastructure. And on top of this, our drilling operation is becoming increasingly efficient, irrespective of pad or single-well setup. Our efforts this year to upgrade and high-grade our rigs are continuing to allow us to accomplish more with fewer rigs.

Day rates for the upgrade rigs are higher, of course, but we're offsetting the higher cost with faster cycle times. Let me give you some examples. The average wells drilled per rig increased 33% to 1.2 wells per rig month in the third quarter of 2012 compared to the first quarter. Average days in the lateral, the most critical part of the hole, dropped 18% through a combination of greater efficiency, improved execution and accuracy. We recently demonstrated our execution capabilities with our North Dakota-Lewisville well, which set a Williston Basin depth record. We drilled it to a total depth of just over 5 miles in 26 days.

So I think the headline is if you take our drilling cycle spud-to-spud, well costs are 25% lower in the third quarter compared to the first quarter of the year in large part because of these drilling efficiencies. This is on top of the 12% improvement in spud-to-spud well costs that we had last year 2011.

Let's touch briefly on completion efficiencies and mention a few positive trends. Completion cycle times have dropped 25% in terms of days from rig release to first production from an average of 76 days last year to 57 days in 2012. Some input costs are also showing favorable trends. For example profit costs, including both ceramic and sand, have dropped as much as 40% over the course of 2012. This has helped us reduce stimulation cost per stage from a high of $124,000 per stage in the first quarter -- in the fourth quarter last year to $98,000 per stage in the third quarter.

Support infrastructure is also catching up with full field development. One good example is water handling. We have access to more water wells, shorter hauling distances, centralized heating and more efficient truck dispatching, all of which improves efficiencies and reduces costs.

These examples give you just a little context to show we're looking at every aspect of our operation, improving them individually and collectively. In the aggregate, these cost reductions and improvements significantly improve capital efficiency and underscore Harold's point about the combination of growth and capital efficiency to create value.

So what does this mean for our future execution? We're set up well for next quarter and next year to reduce Bakken well costs from the current average of $9.2 million per well to $8.2 million per well by the end of 2013. That in turn significantly impacts well economics and drives your returns.

Now let's talk briefly about the components of our production growth. As Harold mentioned, third quarter production increased 55% compared with the same year period last year. In the Bakken, this production was 62,453 barrels of oil equivalent per day in the third quarter. This represents an 81% increase over the third quarter last year and, in terms of the sequential periods, 17% higher than the second quarter. We are currently running 19 operated rigs in the Bakken, which should be sufficient to deliver continued strong production growth in the fourth quarter.

SCOOP production was also excellent. SCOOP contributed 5,183 barrels of oil equivalent per day in the third quarter, a 327% increase over the third quarter of 2011 and a 64% above the second quarter of 2012. We currently have 6 operated rigs in SCOOP and, again, we expect a strong repeat performance in terms of fourth quarter growth.

Now before turning the call over to John, let me give you some color on the exploration activities. At Investor Day, we said we plan to complete 110 exploration wells over the next 2 years. A large portion of this program included an accelerated de-risking program to delineate the prospectivity and productivity of the deeper benches of the Three Forks across a large geographic area, as well as several multi-well full field development down-spacing pilots for the whole petroleum system of the Bakken. We continue apace with planning and preparation for this and expect to kick off these 2-year projects early next year, with first sales to the market in the second half of 2013.

So in summary, Continental is focused on production growth and reducing cycle times and costs, which we expect to generate strong operating and financial results. We're looking for a very strong first quarter and first year in our 5-year growth plan to triple production in proved reserves. And we believe this focus will continue to drive earnings growth and reward your confidence in Continental.

That brings me to the last and perhaps the key factor that will drive this growth, and that is our people. While you're hearing from the 3 of us this morning, these results are generated by our team. And whether it's Rick Muncrief and the drilling completions production teams driving down well costs; Jack Stark and Chris Haugen leading our sub-service efforts; Steve Owen and Jose Bayardo and the land team adding attractive acreage at competitive prices; or Jeff Hume, Kirk Kinnear and Steve Bradley relentlessly focused on erasing the basis differential of the Bakken crude. The continuous strong financial results come from continuous strong execution and the support teams behind them.

For those of you who attended Investor's Day, I hope you came away with a good sense of the breadth and depth of the organization that will deliver these 5-year targets.

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

John D. Hart

Thank you, Rick. A number of positive trends impacted our cash flow and financial position in the third quarter. As noted, our $492 million in EBITDAX was a 46% increase over the third quarter of 2011. We generated a cash margin of 72% during the quarter, which continues our focus on high-margin oil projects. That margin is one we're proud of, and it's something that's pretty stout when you compare it to our peers and industry norms.

Our margins benefited from lower production cost per Boe, a 6% year-over-year improvement to $5.62 per Boe during the quarter. This compares with $5.98 per Boe in the same period of the previous year. The 9-month results were even stronger, an improvement to $5.34, representing $1 improvement from the previous year per Boe.

We've also seen significant improvement in oil price differentials in the third quarter. This primarily relates to the steady increase in rail shipments of oil out of the Bakken. With the rail infrastructure now in place, we can optimize our oil shipments. In November for instance, 65% of our operated Bakken oil will be shipped by rail.

As a result, oil differentials improved significantly in the third quarter, dropping to $9.45 per barrel. September was even better at $5.19 per barrel. Our 2013 guidance on oil differentials allows for some continued volatility, but we believe the situation going forward will be more favorable than our experience during 2012.

A final issue affecting cash flow is our continued effort to hedge against volatility and commodity prices. We've been active in the past 4 months using derivatives to protect our cash flow stream from commodity fluctuations, especially in the case of oil. As detailed in yesterday's press release, we have derivatives representing 4 million barrels of oil in place for the fourth quarter of this year and another 23 million barrels hedged in 2013. Again, our hedging program is designed to ensure strong stable cash flow, enabling us to actively launch into our 5-year growth plan.

Our financial position remains exceptionally strong, supported by another record bond issuance in the third quarter. We completed this $1.2 billion bond issuance at an effective yield of 4.6%, which added significant liquidity to our already strong capitalization.

In closing, I want to emphasize a few select points. The company will focus on continuing strong cash flow growth, improving margins and balance sheet management. We expect that these will be consistent trends for Continental in 2013 and throughout the cycle of our 5-year program.

With that, I'd like to turn the call back over to our operator, and we would be glad to take any questions you may have. Thank you.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Neal Dingmann from SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

First, just question on -- I guess, a couple of housekeeping, I'd say, first on the...

J. Warren Henry

Lisa, this is Warren Henry. We just lost Neal. Are you there?

[Technical Difficulty]

Operator

The next question comes from Leo Mariani from RBC Capital Markets.

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

You talked about improving oil differentials in September. Any thoughts on kind of what you're seeing in October thus far?

Jeffery B. Hume

Leo, this is Jeff. We saw an increase in market opportunity with rail and it moved more to that, so I think you'll be seeing an improvement as we shift to that. As John said, we've got 65% going on rail now. It gives us great flexibility. The good news is we have ample infrastructure to move both by rail and pipeline, so we can switch from one to the other as the market shifts. And we're working that and planning ahead to maximize our value through that marketing effort.

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

Got you. Okay. And in terms of your rig count, you guys talked about 19 operating rigs in the Bakken, 6 in SCOOP. Where do you think those are going to go to by early 2013?

John D. Hart

Well in early 2013, Leo, we'll have -- we'll add a couple of rigs in the Bakken. So we'll be in the 21 to 22 range, I would say, by midyear '13 in the Bakken. And then in the SCOOP, we'll be walking that -- I would say that by midyear, we'll be at 9 rigs in the SCOOP and plan to exit 2012 with 12 rigs in SCOOP.

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

Okay, that's helpful. And can you give us a little bit color around the recent acquisition, 120,000 net acres? Obviously pretty good size. It sounds like that was acreage where you already had significant kind of interest and footprint in. And just kind of any color around what sort of led up to this deal here.

John D. Hart

Yes. It started out as -- we've been working on this for quite some time. It started out as a public offering that was pulled through the commodity pricing. That's when we went to work and started privately negotiating it, and we're very excited. It's basically 2 different contiguous areas. One, we have a majority control; and the other a little bit over 50% control. It's around 70% HBP and 70% operated. It's a great fit strategically for Continental, and we're very excited about it.

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

That's helpful. And I guess when do you go and start to mobilize rigs on to that acreage here?

John D. Hart

Leo, actually, some of this we actually operated on, and we have rigs operating there currently.

Winston Frederick Bott

Yes. So I think the key points for this is how strategic it is, and it's essentially right in the areas where we're operating. It allows us to further our ECO-Pad work. I mean we operate most of this. It allows us just to increase our interest in each of the operated units we're in. And it's right in the heart of where we're working, so it's a real good fit for us. It won't change a lot our operating plans. It won't change our development plans. It's just a question of having more interest in the wells that we already had planned, so it's a real good fit.

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

And I guess it had bumped your CapEx a little bit in 2013. I think you alluded to that in the press release. Just wanted to get a sense of how much you thought that was going to be? And then also what are you guys assuming for average Bakken well cost in 2013?

John D. Hart

We will -- obviously, the transaction hasn't closed. Once it closes, we'll make any adjustments necessary. I think the key point is that this large -- this acquisition, the CapEx is largely cash flow neutral due to the strong production component that's associated with the acquisition. So it's a very minimal net cash flow -- outflow in year '13. And then beyond that, it should be positive. So we're looking at all-in roughly a couple hundred million of CapEx and EBITDAX in '13. But we'll firm that up later once the transaction closes.

Winston Frederick Bott

And you asked -- the second part of your question was well cost. As we've stated at Investor Day, we set a target for ourselves to have average well cost at $8.2 million by the end of the year 2013. So that's a goal we set for ourselves. And the point of some of the color we're giving you is that we see trends heading in that direction, so it gives us confidence that we'll be able to achieve that next year.

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

I guess in terms of your CapEx guidance for '13, are you baking in those savings kind of ratably over the year or using more current well costs?

Winston Frederick Bott

Well when we built that capital budget, we've sort of made the assumption that we would get additional savings. But then that was something that we would use in terms of drilling additional wells. So essentially, we've used the current number. We've taken a conservative approach to that. And we think that, that will play out through 2013, and we've set ourselves a goal. But that capital budget is based on those 2 goals.

Operator

Your next question comes from the line of Doug Leggate from Bank of America Merrill Lynch.

Abhishek Sinha - BofA Merrill Lynch, Research Division

This is Abhi Sinha for Doug Leggate. He's traveling, so we apologize for that. So I just have a couple of questions. So regarding the acquisition, given you already have significant resource debt, so how do you bridge the gap between [indiscernible] in inventory and realizing [indiscernible]?

Harold G. Hamm

Well first of all, as we mentioned, about 70% of this is HBP. So we're not under the gun to be out there developing a lot of new acreage. Some of it, certainly, we will be developing a new acreage on as we go forward. So it's a fit in lot of different ways. So that's the first part of your question.

Winston Frederick Bott

I think the other point is it's really value for effort. So if we're going to drill these wells anyway on these things that we operate, if we're increasing our position in those wells, we're getting more value for the effort that we're putting into operating. And I think that, plus the ability for Continental to leverage our efficiency gains over a bigger program, will continue to drive value for shareholders over the next couple of years. So it really is quite a strategic fit because of that increased efficiency of our operations.

Abhishek Sinha - BofA Merrill Lynch, Research Division

Sure. Okay. What does the consolidation outlook look like now going forward? I mean, are there more deals that you could be participating in, in the near future?

Harold G. Hamm

We'll have to gauge that as we go forward. We have been one of the more active participants out there in aggregating both acreage, and we still see some opportunities. But we're probably coming to a close of that phase over the -- through the balance of this year. We expect to see those opportunities diminish, and so this is especially one that fits us real well.

Abhishek Sinha - BofA Merrill Lynch, Research Division

Sure. And going back to the pad wells, I know you guys talk a good deal about the operating efficiencies. But I wondering about [indiscernible] rates in the pad wells [indiscernible] looking pretty good. Is there anything unusual, long-term frac stages going on that we should be knowing?

John D. Hart

No. They're fairly consistent with the rest of our program. Nothing of note there. The main thing is the cost driver is going to be a lower everyday efficiency driver. The economic driver is around the cost and the ability to execute so much smoother. If you were at our Investor Day, you saw that we had just finished our first simultaneous operations. It's just another level of efficiency that we've gained, and you can count on us furthering those efforts.

Abhishek Sinha - BofA Merrill Lynch, Research Division

Sure. So given that [indiscernible] 45 rigs in the pad wells, 45% of your rigs in your pad well, so is there a point where you might want to reset your estimates on the year [indiscernible]?

John D. Hart

Well, we'll always be watching our well performance to adjust the EURs, if it's warranted right now, we're still at the 603 model. It seems to be working. But I can tell you we're looking at a lot of things with our stimulation design, the wellbore [ph] performance, and we'll continue to look at that. It is year-end time, and that's when we always get ready to finalize our year-end reserves. And so there will be a lot of scrutiny on wellbore [ph] performance.

Abhishek Sinha - BofA Merrill Lynch, Research Division

Sure. And again, where [indiscernible] I'm seeing that we have like production taxes are turning higher. I mean, is that the reason behind something or is that something that will continue? How do we look on that?

John D. Hart

On production taxes, North Dakota has a higher production tax than the average. They're right around 11%, 11.5% up there. So as you drill, that does tend to pull your rate up. Interestingly, as we drill more in the SCOOP province in Oklahoma, we expect to see that overall blended rate moderate. And we're projecting that some for 2013.

Abhishek Sinha - BofA Merrill Lynch, Research Division

Okay. And the last one that I have is, if you could provide any update on the deeper Three Forks potential?

Harold G. Hamm

Yes, we're continuing to proceed ahead with our plan to test both the second and third benches and fourth benches. We've got, as you know, 14 wells planned. We have our first well, the Charlotte #3. The third bench test there has been drilled, and it has been stimulated. And we are now just tuning it up and getting ready to put it on production and get our first production test of the third bench of the Three Forks. I wish -- I'd love to be able to share some additional data right now, but we don't really have any production data yet to share, but it won't be long here. So we're excited about the potential outcome here and we'd be -- hopefully, in 30 days, 60 days, be able to talk about it more.

Jack H. Stark

The other thing I might add is our first full-scale 320 project is Hendrickson. It's a -- we do have regulatory approval on that, so we'll be getting underway before much longer. And we've also had our hearing for our first 160-acre pilot, and that hearing went well. We've not gotten the final approval at this point in time.

Winston Frederick Bott

One other point about that deeper Three Forks potential. Remember what we've talked to you guys about at Investor Day was the context of trying to de-risk this play across all of the deeper benches, but over really quite a large area. So it's a large program. It's going to be executed over the next 18-24 months. And so the goal here is to take everything we've learned in developing the Middle Bakken and the Upper Three Forks and then accelerate the de-risking of that across a broad area and understand the reservoir much quicker and then be able to bring that value forward based on the results that we get. So individual wells here and there will be one thing, but the really thing to watch is how we'll be executing on the overall program and what are the results in terms of understanding the reservoir, its productivity and its deliverability in individual areas and looking for sweet spots, as well as being able to extrapolate out very, very quickly.

Jack H. Stark

And I might add just a little bit color there, Rick, as well. Just to give you a perspective, when we talk about doing a test over a broad footprint here, where actually these tests are going to be spaced out from the very southern end of the play all the way to the northern end. So it's about 100 miles north to south and about 60 miles on an east and west direction that we'll actually be testing and demonstrating the produceability and commerciality of these additional benches. So we are looking at it on a very broad basis here, and I just thought that might add a little bit more perspective.

Operator

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

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

Real quickly with -- in light of the acquisition, can you talk a little bit about what your target or optimal debt to cap will be over time and maybe what you're thinking as far as a targeted or comfort rates for debt to EBITDAX going forward?

John D. Hart

Our longer-term debt to capital and debt to EBITDAX metrics view haven't changed. We continue to be in the position that we want to maintain a very strong, stable balance sheet. With the Samson deal, you'll probably see a little bit of an uptick in the debt initially. However, due to the strong cash flow component on these properties and our ample liquidity beyond that, it will be moderate. And we would expect it to decline as we continue production and moving forward. So we're still in that 1.5 to 1.7 range. And we would expect to -- in that ballpark and to continue improvement.

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

Great. I appreciate that. And then, as you think about the well cost target going forward of $8.2 million, you also mentioned that you're going to be tweaking -- potentially tweaking frac designs, testing some different stimulations. How do I tie those 2 together? Can you kind of give me some color in terms of what inning you are in as far as your well designs pretty? Is it pretty well perfected to get to that $8.2 million? Or do you expect a significant amount of tinkering?

John D. Hart

Well, I think we'll continue to try to -- try some different approaches. The fundamental premise is, is we think that we like the momentum we're starting to see with our cost reductions. And we feel fairly confident that we can achieve that $8.2 million target, as Rick alluded to earlier. And from a stimulation side, we're seeing more capacity in the Williston than what we have traditionally been dealing with. And so more frac crews are available, and everyone's getting more efficient, being able to sharpen their pencil. That includes -- that runs a full gamut from your pumping cost to profit cost. Profit cost coming down, you may be able to -- we may be able to try some more stages in some areas. And the other thing, in some areas we may need more stages, smaller volumes per stage. And so there's all sorts of things we're going to be looking at, but that will continue. We've always done that, and we'll continue in the future. But from a cost standpoint, we feel we're pretty confident about achieving our goal.

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

Okay. I appreciate that. And then one last one. Obviously, you've done a tremendous job with the people you have at delivering your growth to date. As you look at that 5-year plan, do you feel like you have the sufficient people in-house at this point, sufficient by number not by qualification, to execute that a plan going forward? Or will you need to be out in the market getting more people? And does that create any kind of potential burden?

Harold G. Hamm

Well here in Oklahoma City, we've had a talent pool that's given us additional talent that we've utilized, and we will continue to build out the organization somewhat. But certainly -- actually, our operations are a little smaller than they have been over the last year or so at this point, so we'll be picking back up here. But I don't see us significantly adding a great amount of people. Some, somewhat we will be, but as we build out some of these areas to give us additional operating efficiencies such as marketing and a couple of other areas. But overall, we don't see a tremendous influx of people.

Winston Frederick Bott

Yes. One interesting statistic for you, Dave, and that was kind of one of the points to Harold's thing about Oklahoma City. One of the points of moving to Oklahoma City is to be in a larger market. And if you look over the last year, August to August, we've had over 27,000 applicants for the roles that we've been advertising for. So it's a deeper pool. The skills are here. It's an opportunity for us to match the skill sets and the number of people with the 5- and 10-year targets that we set for ourselves. And so while certainly it is something that we always focus on, the move here has sort of launched us into a new arena of being able to get quality people.

Operator

The next question comes from the line of Hsulin Peng from Robert W. Baird.

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

My question is regarding the SCOOP well results. Just wanted to -- wondering if you can share more color in terms of the location and the average costs and how do the rates as compare to the types that you set out on your Analyst Day?

Jack H. Stark

Sure, I'll go ahead and handle the lease location. The location of these wells is down in our Southern Oklahoma SCOOP area. And they're -- I guess I'd say they're in amongst the existing some of the original early wells we drilled out there everywhere from the Lyle on the South side, all the way to our Dana well up on the North side. So they're really good, I guess I'd say, distribution of wells across the play that really gives us a high, high confidence level of the de-risk nature of at least 600 square miles of area there. And we feel we've got the potential to more than double that with our acreage going down to the south. And so -- and what's really encouraging here is that we're seeing very repetitive -- repeatable results there, both north to south. And as we move from, say, the west to the east, we get more oil. So we're continuing to push that oil window on the East side with our wells and several have pushed that, and we're seeing oil cuts out in there in the range of 75%. And so -- anyways, without a map here, it's a little tough to actually lay it out and show you. But it looks -- we have a good distribution there of wells.

John D. Hart

So then I'll also add that since the Investor Day, we had scaled back -- we had been running one frac crew. We had scaled back to give our infrastructure, our pipeline systems a little time to get out ahead based on the highly productive nature of these wells. We're back to working now. So within the next 3 months, you're probably going to see another -- results from another 15 wells down there. So we're going to be seeing a fair amount of growth. And really encouraged, as Jack mentioned, about some of the rates we're seeing, so.

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

Great. And is it fair to assume that you're drilling in both the condensate and the oil fairways?

Jack H. Stark

Yes, we are. We're -- really when you look at this whole area, I mean, right now, I would say we've got or at least half that would be -- it's a gradational change between the condensate and the oil window over -- the whole area there spreads out probably about 25-mile wide, and so there's a gradational change from a more high oil cut on the East side to less oil cut on the West side and more condensate and liquids, natural gas liquids. So our wells that we're drilling are actually being strategically placed along this fairway to help to find those areas with the highest oil cut and the best deliverability. And as I said before, the really encouraging thing here is we're seeing very repeatable results. And so consistency and results across the play are -- even though we're spreading the wells out, we're really encouraged with that.

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

Okay. Sounds good. And my follow-up question is regarding acquisitions. I know you mentioned that you say opportunities are coming to a close. And I was wondering if you meant more because of the potential tax law changes in 2013 that's affecting opportunities or that you have already acquired acreage where you are the majority -- where you own majority of the asset?

Harold G. Hamm

Well, we've seen most of the state acreage, most of the federal acreage has been put up for bid and people have taken that. But also, people that we feel like or companies, small companies that are there to -- seeking to be taken out, perhaps, we see a lot of those have occurred. And in my estimation, we'll see a few of them going forward. There'll still be a few, but perhaps that window is closing.

Operator

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

Yiktat Fung - Jefferies & Company, Inc., Research Division

This is actually Yiktat, Subash's associate, subbing in. Our first question, I guess, is about whether your thoughts are on the oil issue on '13, given pieces with the SCOOP growing but also with Arkoma Woodford falling off. So just trying to guess how you see the ratio staying around that 30% region?

John D. Hart

We have modeled in what we forecast for 2013. We're still in that 30% region on that. So it's about 70% oil, 69% to 70% oil. Interestingly, if you look at us on a total liquids basis, we are higher than that. We would be in the 78%, 79% range on total liquids.

Winston Frederick Bott

And remember next year, as Harold noted for you guys at Investor Day, next year we're going to start breaking those NGLs out. And you'll be able to see total liquids still refer to how much is actually true black oil, but we're going to show you both of those next year.

Jack H. Stark

I might add, too, and you mentioned about SCOOP area, when you look at the total liquids there, you're looking at somewhere in the range of about 60% to 75% total liquids in our condensate and oil fairways there. So that obviously plays a big part in keeping our ratio up there at 70% oil.

Yiktat Fung - Jefferies & Company, Inc., Research Division

On that issue, does the 60% to 75% include ethane? And are you seeing ethane rejection in the Mid-Continent area?

Jack H. Stark

It does give us ethane, yes.

Yiktat Fung - Jefferies & Company, Inc., Research Division

And have you seen ethane injection recently in that area? Or are you still...

Jack H. Stark

Yes, we have. We're seeing ethane rejection.

Yiktat Fung - Jefferies & Company, Inc., Research Division

What would that 60%, 75% be without ethane?

Jack H. Stark

It would be in the range of about 25% to 55% oil on average in those areas.

Yiktat Fung - Jefferies & Company, Inc., Research Division

55% liquids. Okay. And what's kind of your thoughts on the NGL outlook?

Winston Frederick Bott

I think we have to -- we have to check that number for you on what it would be simply without ethane and get back to you. I think that's...

Jack H. Stark

I think it's going be -- it's going to change your liquid -- your NGLs by about 50% is what it's going to do, 40% to 50%.

Winston Frederick Bott

Oh, I see what you're saying. I'm sorry, I was just thinking straight oil.

Jack H. Stark

Right. So it's in between the 2 for a quick answer, but we will check that.

Yiktat Fung - Jefferies & Company, Inc., Research Division

Okay. Great. And just one last question. What's your outlook on NGL pricing going forward?

John D. Hart

Well, we're going to see the ethane remain weak for several years until we get some ethane crackers in and bring that on. We are getting in the SCOOP, getting Mont Belvieu pricing, so we're getting the highest price right now on that and will continue to do that. The overall NGL is going to somewhat improve. We've seen some improvement in that as we get infrastructure built out. So the non-ethane portion, I think, you'll see some improvement over time over the next 2 years as we go forward. So that's kind of our view on it right now. It should be back within 3 to 4 years. We'll be back on good Btu basis, I believe, with oil again.

Operator

Your next question comes from the line of Paul Grigel from Macquarie.

Paul Grigel - Macquarie Research

A quick question for you guys on the production mix, a little bit of housekeeping in the Eastern block where -- what's kind of the oil gas break down there? And then in the Bakken acquisition, what's kind of the production profile right now, the 6,500 barrels? Is it still in the kind of the steep part of the decline curve? Or has it flattened out a little bit more?

John D. Hart

Okay. In the Eastern region, that's 90-plus percent crude oil. It's -- Illinois Basin is normally crude oil production, and so it's 90-plus percent, maybe 92% crude oil. And then on the production, the 6,500 barrels a day, it's a mix. It's -- in that area, we're seeing some shallower decline, so you've had some wells that -- or certainly have been oil production for a while, and then you've got some new wells that have been added in the last year in the development. So a little bit of a mixed bag there.

Paul Grigel - Macquarie Research

Okay. Great. And regarding the cost savings. What's the biggest driver there? Obviously, there's a few different items you guys have mentioned. Is it service cost reduction from the service providers? Is it increasing efficiencies? Is it moving to pads?

John D. Hart

It is both. I mean, it's simply -- I'm not trying to avoid, it's just simple matter. We've seen -- just to give you an idea, from the first quarter of this year to the third quarter this year, we saw cycle times on the drilling side decrease by 25%. So clearly, with the $50,000 a day spread day rate, directional equipment, everything else that's impactful. And the other thing is something we had mentioned earlier, and that is that we now have a little bit of incremental capacity in the Williston Basin across the board with services, which allows for people to provide not only better service, but they're sharpening their pencil because there is a little bit more competition built in the system. So it's all the above.

Winston Frederick Bott

Okay. And we think that's good for the basin. I mean I think as this comes in line and service and cost come down, I think all the operators out there will be able to do a better job and be able to do more and drill more activity because things are just a little bit more economic. The industry did a good job this year in focusing on costs and rig count down from about 15% from its peak. It was probably in May, and it's down about 15%. And so that's provided -- I think everybody is getting a benefit from that now that supply is in line with the demand in terms of services and equipment.

Paul Grigel - Macquarie Research

Okay. And lastly on differentials. Obviously, you guys have talked about how much more is moving toward rail. With a sizable number of pipelines, at least planned at this point in time to come on, is there a need for those pipelines to come along? Or is rail a viable long-term solution, given the different coasts that it can ship to and improve differential pricing?

John D. Hart

No, there's definitely going to be a need for the pipelines because the production growth forecast for the areas is in excess of 1.5 million barrels. It could reach to 2.0 million 2.25 million barrels a day, so it's going to require a full platform of infrastructure build-out. We're seeing right now rail infrastructure build-out that can handle over 1 million barrels a day, and the pipes that are being planned and in progress will take care of the other side of that. So we're going to see a huge shift over the next 2.5 years of markets. We're going to see the differential WTI Gulf Coast differential start to disappear in the first quarter of next year. We'll see how fast that goes. Time is only going to tell. But 2 key pipes coming up are the expansion of the Seaway pipe, which will take place late January or early February; and then the Keystone pipeline from Cushing to Houston. Those 2 ought to give us our greatest improvement on the pipeline infrastructure. It will take more barrels out of Cushing and open that thoroughfare down to that area. But at the same time, rail is improving significantly. We have an excess of rail capacity at this time, which is wonderful. We're able to hit all the markets. We're finding new markets on both coasts. And I think you've been reading about some of that in the press, where new markets are opening up. So our barrel refineries understand the value of our barrel, and they're coming to us readily right now.

Operator

Your next question comes from Noel Parks from Ladenburg Thalmann.

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

Just a couple of questions, and sorry if you talked about some of these before. I got on a little late. Could you talk a little bit more about your progress in the extensional areas on the Montana side sort of, I suppose, North and South of Elm Coulee?

Jack H. Stark

Sure. Noel, this is Jack. We continue to drill our wells up North there. We've got about 4 rigs there in Montana and focusing in the area. And we've -- as we showed in the Investor Conference there, we've managed to push that trend further North. The commercial -- the economic limit that used to exist for the Elm Coulee Field has now been pushed almost 10 miles to the North encompassing about another 100,000 net acres up to the North there. And the results we're seeing there, as you see in this quarter, we had what, our average was about 886 barrels of oil equivalent per day. Those wells are looking very good, continue to see comparable results over a broad area, just north of the, oh, I'd say the western half of Elm Coulee. And we're continuing to push that East on to our acreage. I guess I'd just say the -- kind of without a map, I'm trying to describe it here. But we pushed the halo to the North 10 miles, and now we're starting to push it up to the river and a bit to the East of there with the wells that we're drilling. And actually here recently, we've had some results out on the East side that are encouraging, and so we're optimistic about our ability to continue to expand to seeing both North and East.

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

Okay. And actually on the consolidation side, has there been much going on the Montana side as far as maybe some of the operators who were involved? I'm thinking small interest sort of back in the heyday of you starting Elm Coulee. Or as you head further West, is there just not that much left to do?

Harold G. Hamm

Well, there was basically 3 companies involved there originally. Continental was probably the largest one of those, and then we've seen 2 other companies that both were marketed. One of them is owned by XTO and the other is by a Canadian company. And all of those are pretty stable. I don't see those changing. So there may be some opportunities over there, but probably not as much as we've seen on the North Dakota side.

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

Okay. Great. I was just wondering if maybe as your scale probably keeps growing and growing out there, whether you might be in a position to be a little bit more aggressive and talk to some of these other folks than they might be, if those prices are a smaller part of their overall portfolio.

Harold G. Hamm

That opportunity could exist. We'll stay open to it. There is some small operations over there that we've been in right till the end but, well, probably not as much as on the North Dakota side.

Operator

Your next question comes from the line of Gail Nicholson from KLR Group.

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Just a couple more Montana questions. You had talked at EnerCom about a 3-mile lateral well over Montana. Have you guys completed that yet?

John D. Hart

Yes, we completed that one, Gail, and it has come on just under 800 Boe per day and is still flowing about 300 Boe per day, which is really encouraging. Those wells in that particular area have a tendency to load up a little quicker than we see on the North Dakota side. But then they experience sometimes a shallower decline, so very encouraged by what we've seen. That well is the Mott well.

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Do you plan to drill anymore 3-mile lateral test over there in 2013?

John D. Hart

Well, that particular case was somewhat unique in that we had just with the land setup. We're going to continue to watch that. As Rick mentioned earlier, we just completed or just drilled the first 3-mile lateral in the North Dakota side, which, I have to think, that was a lateral with a total measured depth 26,500 feet. So certainly, a depth record, we think, for the basin. So we'll continue to watch advancing technology and the application of it. It could create -- and we anticipate, it will create additional opportunities for us.

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Okay. And then just looking at the Three Forks on the Montana side. I know I think back in 2008, you guys drilled a test well that wasn't successful. What do you think of the potential there?

Jack H. Stark

Well, that's a good question. There's not a lot of Three Forks tests that have been done out there. In 2008, we were really behind it technically to build traction. We see some activity on the very East side of the state there, around the state line of North Dakota and Montana, where we're seeing some Three Forks production there. And so I expect to see it work its way from the East to the West. But we've done some core workout in the Elm Coulee area, and we're encouraged with what we saw. So stay tuned, we'll continue to evaluate.

Gail A. Nicholson - KLR Group Holdings, LLC, Research Division

Okay. Great. And then one final question. Just looking at the Red River production, it looks like it declined during the quarter versus Q2. Was that any infrastructure? Or was that the natural declines in the field finally? Or just a little update on that.

John D. Hart

We just had a little bit of natural decline, but nothing of note that's a problem, certainly.

Operator

I would now like to the call over to Mr. Hamm for closing remarks.

Harold G. Hamm

Thank you, everybody, for joining the call today. And we appreciate your interest as we go forward here with the new plan and certainly the new plays that we're involved in. So we'll be talking to you next quarter. Thank you very much.

Operator

Thank you for joining today's conference call. This concludes the presentation. You may now disconnect. Good day.

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