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Continental Resources, Inc. (NYSE:CLR)

Q2 2012 Earnings Call

August 9, 2012 10:00 AM ET

Executives

Harold Hamm – Chairman and CEO

Rick Bott – President and COO

John Hart – SVP, CFO and Treasurer

Richard Muncrief – SVP, Operations

Jack Stark – SVP, Exploration

Steve Owen – SVP, Land

Jeff Hume – Vice Chairman, Strategic Growth Initiatives

Analysts

Subash Chandra – Jefferies

Leo Mariani – RBC

Pearce Hammond – Simmons

Brian Corales – Howard Weil

Hsulin Peng – Robert W Baird

Noel Parks – Ladenburg Thalmann

Eli Kantor – IBERIA Capital

Rudy Hokanson – Barrington Research

Andrew Coleman – Raymond James

Operator

Good day, ladies and gentlemen, and welcome to the Continental Resources Second 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 open the floor to questions. Other members of management are also available to answer your questions.

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

Harold Hamm

Good morning, everyone. Thank you for joining us for Continental’s second quarter earnings call. Two years ago, we met with many of you here in Oklahoma City at our first Continental Resources’ Investor Day. At that conference, we unveiled our five-year plan to triple production in proved reserves by year-end 2014. At that time, some of you may have been skeptical that we could do that, but we will meet that production goal by early- to mid-2013, 18 to 24 months ahead of that plan. And we moved the company headquarters from Enid, Oklahoma to Oklahoma City in the meantime.

During June, we achieved a corporate production milestone of 100,000 barrels per day. Our second quarter 2012 production of 94,852 BOEPD was 76% higher than the same quarter last year and 11% above production for the first quarter of 2012. Our second quarter operating and financial results were also exceptionally strong.

Based on our strong results, we raised 2012 production growth guidance as a whole to a range of 57% to 59% funded by a $3 billion CapEx budget. Continental Resources continues to ramp up production in our premier Bakken asset, one of the largest and most prolific oil fields discovered in more than 40 years and we’ve seen tremendous value in our position also within the Anadarko Woodford.

Our teams are increasing the value of these assets through acceleration of our development plan and they continue to perform at an exceptional level. This allowed us to maintain industry-leading production momentum and margins while reducing our rig count. In the Bakken, we improved drilling cycle times by approximately 30%; in essence, we are accomplishing more with less. By year-end 2013, we expect to substantially de-risk and establish production in each spacing unit at our North Dakota Bakken acreage. This will allow us to employ more ECO-Pad rigs.

We’ve already made significant progress and are rapidly transforming from single well to ECO-Pad drilling with nearly half of our Bakken rigs currently drilling on ECO-Pads. Pad drilling is yielding up to 10% cost savings per well. As we move into full development mode, we expect to generate further efficiencies that will continue to improve the value of this asset.

Underpinning our strong growth in production and proved reserves is a solid financial foundation. Toward this end, we’ve layered in hedges to establish cash flow and are maintaining a low level of long-term debt for the size of our company. Our strong balance sheet provides flexibility when acreage consolidation or other growth opportunities may arise, as we’ve seen throughout this last year.

Together, our strong balance sheet and operational control enables us to maintain high margins and cash flow growth. Superior assets, operational excellence, and financial flexibility are the essential elements of our strategy, which we strongly believe will maximize value for shareholders. We’ve taken a bold leadership position in our two key resource plays, and we have a high level of confidence in long-term value of oil and natural gas. We’re proud to be helping America become energy independent.

With that, I would like to turn the call over to Rick Bott for additional color and detail. Rick?

Rick Bott

Thank you, Harold. These are really fascinating times at Continental Resources and since joining the team a few months ago, I have really been struck by the variety of opportunities that we have in front of us. In addition, we have an excellent team of people with a strong entrepreneurial drive continuing to create value from these opportunities.

But a couple things you said I think are worth really restating for our second-quarter highlights. 76% year-over-year production growth, and an increase of 11% increase over the first quarter of 2012, as well as a 48% year-over-year growth in EBITDA, as you noted.

We also had a 20% increase in proved reserves, to 610 million barrels of oil equivalent from the end of 2011 based on our mid-year internal evaluation. Continued improvement of our operating efficiencies, which, along with increased capital spending, has allowed us to simultaneously de-risk and extend the proven inventory in the Williston basin, while bringing forward the value of these high rate of return wells.

With this in mind, let’s talk about the three primary reasons for the additional capital so far this year and for the remainder of year, which as Harold noted, will be $3 billion for the full year and deliver an increase in production growth to a range of 57% to 59%.

Firstly, over the year, we’ve reduced cycle times by 30%, which resulted in more net wells drilled per rig. Because we are opportunity-rich and have generated such efficiencies, we looked at all our options and decided to accelerate our efforts to unlock the value where prudent.

Secondly, as we look at all the players in the Bakken, the entire industry is wrestling with cost escalation and has really chosen to focus on their own operations and not participate in wells others drill. We have chosen a contrarian long-term approach, and instead, have taken up these available interests in both our operated wells and those operated by others.

This has resulted in a 28% higher working interest on average in our wells drilled during the first half of the year, I’m including both the Bakken and Woodford there, which also translates to more net wells per rig.

In addition to the pool of interest I just mentioned, we also increased working interest through trades, farm-ins, ongoing leasing and strategic acquisitions. We have seen this as an opportunity to take higher interest in wells we really like.

This acceleration and increased interest were the two primary contributors to the increased capital announced for the year and work to support our long-term strategy as well as the record production growth we’re announcing.

And, thirdly, we also saw some cost creep on operated and non-operated wells, like others. Non-operated wells are running $2 million higher than our operated wells, which are currently averaging $9.2 million in the North Dakota Bakken, and about $9.5 million in the Southeast Cana, Anadarko Woodford area.

Continental continues to work with service providers to bring down operating costs in order to maintain this low-cost leadership through operational efficiencies, addressing supply chain issues and reducing the strain on infrastructure in the areas in which we operate. And where – when we’ve needed to, we’ve also had – laid down some iron.

For the second quarter, we had an average oil differential of $12.63, but we started the period in April with a monthly average of more than $18 per barrel. Due to this volatility, we adjusted our guidance a couple of weeks ago. As more pipeline capacity out of the Bakken increases, we expect differentials to come down. The key takeaway, though, is what we’re doing to maximize the long-term value of Bakken crude.

We continue to add opportunities to transport Bakken oil to coastal U.S. refineries that yield the highest net price per barrel at the wellhead. Additionally, we are actively supporting expansion and construction of a new pipeline. These and other infrastructure improvements such as the reversal and expansion of the Seaway Pipeline, as well as increased rail capacity, will result in realizing the intrinsic value of the high-quality Bakken crude.

Now let’s shift gears a bit and talk about what’s ahead in the second half of 2012. While some operators have chosen to retrench to their core areas in the Bakken, Continental continues to explore and expand the geographic limits of the play. Since January 2012, our step-out and exploration drilling program has de-risked approximately 50,000 additional net acres including areas east and west of Nesson anticline, north of Elm Coulee, and south along the southern extent of the play. We’ve also established commercial production using the newest technologies in areas that were previously considered marginal.

A key focus of our investment will be testing approximately eight additional Bakken Three Forks wells in the lower benches of the formation, half of those being in the second and half in the third bench. We’ve proven that the second bench to be commercial with the first two wells and now we are past – now that we’re past some of our permitting issues, we are preparing to spud these additional second bench tests and our first test in the third bench to extend the play vertically. While the next two tests won’t be completed by the Investor Day on October 9, we hope to have some color on them for you by then.

Our first priority in the lower benches is to establish productivity across the play because – and because of what we learned in the Bakken, we feel we’ll be able to de-risk this play much more efficiently and quickly.

Just moving south to the Anadarko Woodford, our production has increased fourfold over the past year. We are reducing our rig fleet there and concentrating our remaining six operated rigs in the Southeast Cana area, where the wells are much bigger and have a greater oil component. The economics of these wells continues to be very strong.

Finally, another milestone, as Harold mentioned, for us as a company has been the successful move of our headquarters to Oklahoma City, which we completed – we will complete literally in the next few days. The move is proving to be a huge success in terms of recruiting and has helped us bring in senior, experienced hands as well as bright young professionals who want to work for the leading operator in the Bakken and Anadarko Woodford.

As we responsibly grow production and proved reserves, we’re also focused on safety and environmental compliance, assuring we continue to protect the health of our people and the environment where we operate.

In closing, let me step back from the quarter results and detailed financials and summarize what I see. Over the past three decades, I’ve had the pleasure and opportunity to work with some very talented people to explore, develop and commercialize many large oil and gas fields in challenging and remote locations around the world. Additionally, it has been a very long time since North America has had the good fortune to develop a world-class field as immense as the Bakken.

The entire country is just now coming to grips with the scale of the opportunity, the timeframe required to develop it and the investment needed in infrastructure and people. The entrepreneurial people of Continental are at the forefront of the creative application of technology in our industry, which is unlocking the code and pushing the limits of developing unconventional resources like this. The issues we face today are clearly surmountable, and I can think of no better team than the people at Continental to lead the way.

With that, I’d like to turn the call over to CFO, John Hart, to discuss the financial results.

John Hart

Thank you, Rick. During the second quarter, we reported net income of $406 million, or $2.25 per diluted share. This compares to $239 million, or $1.33 per diluted share, in 2011. Our adjusted clean EPS, adjusting for unrealized derivatives, impairment charges and similar items, was $0.68 per diluted share, which compares to $0.60 in 2011. We also reported $422 million in EBITDAX, which was 48% higher than 2011.

The strength of our earnings growth is a strong testament to the quality and high margins generated by our underlying assets. This quality is further evidenced by the per unit improvements reported in actual production expense and G&A results, as well as our revised annual guidance for the full year.

Over the years, Continental has paid particular attention to maintaining the strength of its balance sheet, which provides flexibility when we have particularly strong growth opportunities. This is precisely where we are today.

Even with stronger than expected production growth and a higher CapEx spend in the first half of the year, our debt to EBITDAX at June 30 was 1.4 times based on the trailing 12-months EBTIDAX. Of course, our cash flow is also trending higher quarter-upon-quarter throughout that period. Given this fact, we don’t expect debt to EBITDAX to trend significantly higher.

We also have ample liquidity. Along these lines, last week we announced an increase in the commitment level under our revolving credit facility to $1.5 billion, and a similar increase in the borrowing base to $2.75 billion, demonstrating the willingness of our banks to continue supporting Continental’s growth strategy with its focus on oil concentrated production.

With this increase, and our ability to revise further if necessary, we have significant available capacity under our revolving credit facility. Cash margins remained strong, consistently in the 73% to 75% range from 2010 through the first half of this year, supported by strong crude oil prices and low operating costs. We remain focused on capital discipline and maximizing the value of our premium assets. We are growing at an accelerated pace while maintaining credit metrics as strong as any of our peers and stronger than most. We don’t expect this to change.

With that, I think we’re ready to start the Q&A portion of the call. And I’ll turn it back over to the operator. Thank you.

Question-and-Answer Session

Operator

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

Subash Chandra – Jefferies

Yeah, hi. Good morning, everybody.

Harold Hamm

Good morning.

Rick Bott

Good morning.

John Hart

Good morning, Subash.

Subash Chandra – Jefferies

Question – I guess if you can maybe add some specifics to this, but in your original view in the CapEx of drilling CapEx that you had in mind, a little under $2 billion, $1.65 billion or so, and the $3 billion, could you just talk out maybe the number of wells you had assumed in the original CapEx guidance? And the number of wells you’re now targeting for 2012 on a net basis?

Richard Muncrief

Yes, Subash, it’s Rick Muncrief. If you go back to our original budget that we laid out right at the very first of the year, we were looking at 249 net wells in the budget as a company. And what we’re saying now is we will be at a level of wells that are available to be completed of 330 net wells at year-end.

Subash Chandra – Jefferies

Okay. So the 249 was with the $1.65 billion budget?

Richard Muncrief

Yes, that’s correct.

Subash Chandra – Jefferies

Okay. Terrific. Thanks. And then so, for 2013 and I guess this comes to the broader question of what to expect in October, you had a five-year plan, you were clearly driven to overachieve. Should we think about the revised five-year plan as sort of really a similar growth track that you would attempt to accomplish? And this time, if you can shed some light on what sort of spending discipline you might have to achieve those numbers? And in particular, what you’re thinking for 2013 CapEx, if it’s not too early to talk about that?

Harold Hamm

Go ahead, John.

John Hart

We are currently working on 2013, and in relation to that, we have a multi-decade asset and we’re looking at growth rates not only for 2013, but for the next five and ten years and how we best manage those. We have a commitment to maintaining our capital discipline. But we also have an extremely high quality asset where we effectively return cash quickly, which enables us to keep our metrics strong, while increasing the level of activity in our operations.

For 2013, we expect to have an announcement on that in October when we have our Investor Day, and we’re actively working on that. It’s safe to say that we have a tremendous amount of momentum in wells ready for completion carrying out of this year going into next year.

We expect to continue generating strong high margin growth for a considerable period of time in the future, but doing that in a way that also balances with our long-term commitment over 45 years of operating to maintain our credit.

Subash Chandra – Jefferies

Sure.

Harold Hamm

Yeah. I had one more comment, too, Subash, in regard to that. A part of it is cost, and we’re actually transitioning in this play now. We’re seeing a transition happen from people basically scurrying to take care of their leasehold commitments and actually moving on to development. So we’re seeing that happen. And as it happens, we’ll see pullback in the level of activity up there, we believe, and to a point that we can all control cost. And so the emphasis we see across the field, operator by operator, is renewed interest in keeping those costs in line. And when everybody’s scurrying around to hold leases, you can do things you wouldn’t do as you go through development.

Subash Chandra – Jefferies

And, Harold, I was wondering, say the revised five-year plan, will there be a target for cash flow neutrality?

John Hart

That is something that we certainly always continually evaluate. We balance cash flow neutrality with a number of factors. We look at our debt metrics, we look at the quality of our asset and the value of pulling that present value forward. So there are a number of factors in there. We have – the important part of, I think, your question, if I could rephrase quickly, is we’re rapidly approaching a period where in the Bakken, for instance, we’ll have that production, held by production, those leases held by production. So we have the ability to be cash flow neutral in a very rapid and succinct period of time that’s coming. With that, you balance it in light of the asset quality and the opportunity and the preservation of your metrics. So that is certainly one of the factors that we consider and we balance all of those throughout that.

Subash Chandra – Jefferies

Okay. And just a couple and I’ll hop back in the queue. One is on the hedging losses for the quarter. I guess you’re not alone in this and I’m trying to get my head around what the swaps and collars might mean, how – if we’re getting a hedging loss on a realized basis and how we should model the second half of the year those hedges? And second is if you have any appetite going forward to sell some of your non-core assets? Thank you.

John Hart

Related to the hedges, and if I don’t fully get your question, please come back to me. We have an active hedging program. We utilize hedges to stabilize long-term cash flow, and as part of that, that balancing that we spoke of previously, it help us to project and make our longer-term capital and growth plans based on that.

During the second quarter, we obviously had an extremely sizable and realized gain. We had a small realized loss. Realized loss is obviously the current positions expiring during that period. And particularly in the latter half of May and June, you had strong movements in crude oil that moved our positions into a significant asset position.

For the second half of the year, the position summary is fully disclosed in our equity position. And it really depends on what oil prices do. Our hedges in general are locked in around $90 to $95 and movements outside of those bands are where you tend to get larger gains and losses on that. And it really depends on the strength of the economy and what crude oil prices do for the back half of the year.

Rick Bott

I think one point to add to that, however, is just the fundamental reason for that and that’s defend the capital program going forward to continue to generate the growth that we’ve seen.

Harold Hamm

One part of your question that wasn’t answered was on the assets that – we have sold some older, mature assets and that have a limited growth. Good assets, but some limited growth. And we will continue that approach as we go forward.

Subash Chandra – Jefferies

Thanks, everyone.

Operator

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

Leo Mariani – RBC

Hey, guys. I know you have a big sort of initiative to start getting service cost reductions and your well cost down. Clearly, you’ve dropped a significant number of rigs at this point. Have you seen any early returns on that in terms of service cost reduction?

Richard Muncrief

We’re seeing some anecdotal evidence in that, and I’ll give you – the most recent happened about 15 minutes after our press release last night when we got an email from a service provider that says they’re voluntarily dropping their costs or prices for us. So we are seeing that. We’re seeing continued improvement or cycle times, and so we’re – we are optimistic about what the future holds on the operated side.

On the non-operated side, where we’ve seen even more pressures, we stated that, on average, in our non-operated wells, those costs are running, in essence, $2 million higher than ours. We have not seen that yet. I know that in comparing what some of the other companies have reported, they all point to the fact that they anticipate that and they’re building that in their models.

But to be real honest, we have not seen that show up yet on the invoices that we’re signing. And so, at the end of the day, we’re going to continue to do what we can do to control that and try to influence costs throughout the basin in a very positive, proactive way.

Leo Mariani – RBC

All right. Well, that’s good to hear. In terms of Southeast Cana, obviously, you guys have focused a lot of activity there. Can you give any more color on kind of recent wells in terms of what you think EURs are trending towards? And what’s the oil percentage on some of those recent wells, also?

Harold Hamm

Well, as we’ve stated, this is an older area, a very significant area for us and it’s a very competitive area right now. So we’re not talking about it to a great extent. We will put a lot of color around that at Investor Day discussion. We’re going to be prepared to discuss it very fully. However, you see the strength of some of these wells here, it’s phenomenal.

Rick Bott

Yes, I think the takeaway there is what we’d noted, that the economics there were still really very strong. And shifting to the Southeast area, as we have done, we think is the right thing to do. We think it’s going to continue to lead to that production growth that we’ve seen and we like the results of the wells we’re seeing there.

Leo Mariani – RBC

Okay, got you. In terms of just activity levels in general, clearly, hopefully, you’ll see some positive trends in the service cost reductions, and would you see those come down over the course of the year and oil prices hanging at $90, would you guys think about starting to ramp up the rig count a little bit?

Harold Hamm

We may come back on with an additional rig or two next year. I don’t anticipate that we will this year.

Leo Mariani – RBC

Got you. Just shifting over to something you haven’t mentioned in a long time, the Arkoma Woodford. Just looking at your production data, it looks like your production was actually up a tiny bit this quarter versus the previous quarter. I didn’t think there was any activity there, I wasn’t sure if maybe you guys have started some new activity there or there’s anything kind of going on in that area?

Richard Muncrief

We did see a slight increase down there. And I think we attribute that to some production optimization efforts both on the operated and non-operated standpoint. I think as volumes have stabilized down there, systems have been able to – people have come in and done production optimization, low capital type work. And I know on our side it’s been very, very minimal activity, no new drilling, no new completions in the last quarter. So it’s just a lot of little things that are having, in essence, a flattening of the decline, offsetting the decline.

Rick Bott

And that’s a good point, and I think, as Rick said, there’s not a lot of additional drilling and effort there. But I think there and other places we operate, particularly the Red River Units, we’ve continued to see production optimization efforts real yield very, very high rates of return so we like the things that our teams are doing in these areas to continue to squeeze out additional barrels and find additional opportunities either behind pipe or other things like that that they can get without a rig.

Leo Mariani – RBC

All right. Thanks, guys.

Harold Hamm

Yup.

Operator

And your next question comes from the line of Pearce Hammond from Simmons. Please proceed.

Pearce Hammond – Simmons

Good morning.

Harold Hamm

Good morning.

Pearce Hammond – Simmons

What would you estimate is your current base decline right now?

John Hart

I believe that number is about 16%.

Pearce Hammond – Simmons

And do you think that’ll be about that level at the end of the year?

John Hart

It should not be much – any less than that, it’s going to be in that range. I don’t see a lot of change within the six-month period right.

Pearce Hammond – Simmons

And then turning to asset divestitures that you were talking about earlier, do you care to quantify how much you think you might be able to sell non-core assets either this year or next year?

Rick Bott

I think it’s probably not the right thing to sort of give a quantification. I think really it more the point is that as we look for that capital efficiency and try to use both our people resources and our capital, we’re focusing on areas that we’re going to get the highest rate of return. And there’s a lot of old things in the inventory that can’t really compete with the Bakken. So we’ll continue to look for those opportunities and be opportunistic and look at the right time to, perhaps, market those or find some other structure to maximize the value, bring it forward. So we’re not really quantifying. It’s not a big effort and a big focus. However, we continue to see things that we can do that just continue to make us more efficient.

Pearce Hammond – Simmons

Great. And last one for me is, where are you currently on your percentage of your North Dakota acreage that’s already held? And then where do you think you could be at the end of this year and then at the end of 2013?

Harold Hamm

Yeah. Our de-risked area in the North Dakota Bakken will be 97% by year-end of 2013, and overall de-risked and exploratory will be at 83% by the same time period.

Pearce Hammond – Simmons

And how much acreage do you have held right now? What percentage of your North Dakota acreage is held?

Harold Hamm

Goodness. It’s probably – let’s see, about 72% on the de-risked and about 60% overall.

Pearce Hammond – Simmons

Thank you very much.

Harold Hamm

Yes, sir.

Operator

And your next question comes from the line of Brian Corales with Howard Weil. Please proceed.

Brian Corales – Howard Weil

Good morning, guys.

Harold Hamm

Good morning.

John Hart

Good morning.

Rick Bott

Good morning.

Brian Corales – Howard Weil

A question – at your current rig count, with the 19 in the Bakken and the 6 or 7 in the Cana, what would that CapEx be if that’s not increased or decreased on an annualized basis?

Richard Muncrief

We are...

Rick Bott

I don’t know that we have it broken out –

Richard Muncrief

I don’t have it broken – I’ll have to think through that, Brian, for just a minute, and we can circle back with you on that.

Brian Corales – Howard Weil

Okay.

Richard Muncrief

Sorry.

Brian Corales – Howard Weil

And then one other one, on the cost side, we have seen basically every one of your peers as well in the Bakken have their well costs increase. Is there a certain area that – is it a little bit from a lot of different things or is it one area that was driving that? And then two, where do you think you can drive down the cost going forward?

Richard Muncrief

Brian, what we have seen to start with, if we go back over the last 12 to 18 months, where we have actually seen a flattening and slight decrease has been on the stimulation side. And I’ll start with that. The increases have been in a lot of areas, some of which you wouldn’t really think about, things like material for locations. The predominant material up there is a scoria, a native rock. And the cost of that on our numbers are up about 30% year-over-year. Our day rates on drilling rigs, we’ve upgraded our rig fleet, that was about a 20% increase year-over-year to try to get better crude, better iron, walking capabilities.

Trucking, some of our numbers are as much as 40% to 50% increase on an hourly basis just due to the unbelievable demand. Rental tools were up in the 30% to 40%. And cementing is flat. Directional services, we’ve seen some pressure there, it’s in the 10% to 15% year-over-year. And that’s driven as much by the demand going on nationwide. So those are just a handful of – to answer your question, we see it somewhat across the board. So our plan is to go in line item by line item on our AFPs and develop clear strategies and tactics to start addressing these.

Brian Corales – Howard Weil

Okay. That was helpful. And then one final one, if I can. The – I lost my train of thought I apologize. I guess that’s all from me. Sorry about that.

Rick Bott

Thank you.

Operator

And your next question comes from the line of Hsulin Peng with Robert W Baird. Please proceed.

Hsulin Peng – Robert W Baird

Good morning, gentlemen. Just one follow-up question on the well costs. So the $9.2 million, I was wondering if that – is that for your – under your ECO-Pad or that on a per well basis? I guess I’m trying to understand if – how that compares to the $8.5 million or the $7.7 million previously?

John Hart

Yeah, I think the $9.2 million is our average for single wells, which compares with the $8.5 million range. The ECO-Pad, we’re still seeing up to 10% savings there so, in essence, you’re in the – still in the $8.5 million – $8.4 million to $8.5 million for an ECO-Pad individual well. What we try to do is have an apples-to-apples comparison on cost. And at this point in time, a lot of our other operators are just now getting some of their Pad drilling results in.

Hsulin Peng – Robert W Baird

Great. And –

Rick Bott

Yeah. And as we pointed out, we’re still out there exploring and extending the limits of the play. So we’ve got a number of singles that are out there. I think Harold mentioned the number of ECO-Pad rigs right now was about 50%, but we’ve still got another half of our fleet out there extending these plays and working in areas and testing out new technology.

Hsulin Peng – Robert W Baird

Okay. Great. And do you have a target as to what you think you can get that $5.2 million down to or it just kind of depends on, I guess, negotiation with the service providers at this point?

Richard Muncrief

Yes. We’re working at that very diligently right now. We’re setting those internal targets. I think, once again, will be able here at the Analyst Day to lay out a real clear target and also what our budget for next year will look like.

Hsulin Peng – Robert W Baird

Okay.

Rick Bott

And, Hsulin, just to add one point to Rick’s comments there, I think we’ve talked before earlier in the quarter about what we had hoped to achieve from cost exercises. But just so you know, we’re sort of carrying that – those new capital costs – we’re carrying that forward for the rest of the year. And so we’re taking a conservative approach when we talk to you about our capital. We’re not building in any particular gains there, but we’re working hard to try to make sure that we get them if we can.

Hsulin Peng – Robert W Baird

Okay. No, that sounds good. And then, also, a follow-up question to, I guess, about trying to frame your 2013 growth prospects. I understand that we’ll get more information on the Analyst Day. But can you help us think about that? So, for example, if we were to hold your rebuilding CapEx the same in 2013, what kind of growth rate can we think about? Or another way could be, if you spend within cash flow next year, what does that mean in terms of your production growth?

John Hart

We look at it in a variety of ways also. Within cash flow is one of those ways that various set numbers, with various other assumptions and the number of varieties. We’re currently working through those aggressively. What I think is safe to say is that we have an extremely strong asset that is continuing to generate significant growth. That level of CapEx would generate a large growth rate level.

There are a number of variables, as we said here, in early August that will impact us on our 2013 capital budget, obviously. Oil price is one of those. A significant – a $10 move up in oil, obviously generate – with the level of production that we have built this company up to and the level of production that we have built in coming forth already, puts off a tremendous amount of cash flow. $10 move up or left or right obviously changes those variables significantly. We consider those various infrastructure issues and everything else we factor all of those in.

Our intent for this company is to build a long-term cash flow generating self-sustaining legacy company and quarter-to-quarter and year-to-year is certainly an aspect of that, but that’s a tactical. We’re as focused on the long-term strategic and harvesting this value. We do expect 2013 to be another good strong solid year, levels of ranges and numbers yet, we’re still – we’re factoring through those now as we consider the variables.

Hsulin Peng – Robert W Baird

Okay, no, understand. And then last question is I know one of the factors that you mentioned is your balance sheet. And so in terms of – your balance sheet is very strong, there’s no question about it. And I know previously you had mentioned your comfort level being around debt to EBITDAX around 1.5 times, which I know there are many peers who are – of your peers that are higher than that. So I was just wondering if you would – if that’s still your long-term sort of target or would you consider raising that comfort level.

John Hart

I think the way you look at that and the way you phrased it is appropriate. It’s a long-term target. There are periods where you’re below that, there are periods where you’re above that. If you look back to early 2009, we were around 1.75 times, 1.8 times. If you look back to the – further back into the company’s history when they ramped up the development of Cedar Hills, some of those ratios went up, but then they ebb back down as the production comes on and the cash flow comes from that. So it’s not a set line in the sand where you’re never above or never below that. We were as low as around 1 times earlier.

So you look at it from a longer-term perspective, so I don’t overly dwell on it. What I dwell on is the long-term focus of the company, not one quarter or the next, but the year and the next year and how you manage that. So it is our target, it is our goal, and with our asset quality and the cash coming from that, we have the ability to maintain in or better than that range. That doesn’t mean there wouldn’t be a period where you’re above it, but it does mean that you have the ability with assets to moderate.

Hsulin Peng – Robert W Baird

Okay, great. Thank you so much for the color.

Operator

And your next question comes from the line of Noel Parks with Ladenburg Thalmann. Please proceed.

Noel Parks – Ladenburg Thalmann

Good morning.

Harold Hamm

Good morning, Noel.

John Hart

Good morning.

Noel Parks – Ladenburg Thalmann

A couple things, looking at the Three Forks, the second and third benches, I was wondering, do you have an update on how that first well, I think it was the Charlotte well, is performing now? Is it roughly according to the – a similar decline curve as the Middle Bakken well or is this closer to your expectation?

Jack Stark

Yes, Noel. It’s doing very well. It’s been online for about nine months, produced about 63,000 barrels of oil, and is performing right in line with our – typical Three Forks producer out there. And I’ll mention that the Sunline well, which was the other one that was drilled about 20 miles away, has produced about 52,000 barrels of oil. And it’s been on – oh, probably, I think it’s been on – when you look at the downtime in there, it’s probably only been on for about three, maybe four months.

So both performing very nicely, and we’re really looking forward to getting going on our first third bench test out here. We had a permitting issue that was just procedural, but it’s not a problem, but we’re just going through the process to get it done. And so look forward to spudding that well probably late this month, okay. The hearing is in – like in the – I think it’s the 22nd, and we’ll get a permit then and be able to just come right out and go. And as you know, we’ve got plans to drill eight additional tests out there, four in the second bench, four in the third bench. And so – and these tests, they’re not really stacked on top of each other. They’re going to be 90 miles really from north to south to where we’ll actually be drilling these and about 60 miles east to west.

So we’re looking at trying to get a broad picture of how this Three Forks second and third benches will perform. And we’ll hopefully have great results to report from that and be able to accelerate the development of those (inaudible). But we’re in a stage right now, we’re just trying to demonstrate distribution and commerciality, and then we’ll take it from there.

Noel Parks – Ladenburg Thalmann

Great. And at this point, is the main thing you’re looking for just a better understanding of the geology? Do you think that – I mean, as best you know at this point, do you think the completions are going to be pretty much within the range of what’s routine across sort of all the different areas of the Bakken you’re doing now?

Jack Stark

Sure. I think that, Noel, we’ve got – actually, we’re taking 10 cores out here. But there’s just a whole – I mean there’s a hundred or thousands of wells out here that have been drilled and penetrated it. So we’ve actually been able to use the electric logs that exist out there, correlate it back to the cores, and be – and we’ve mapped out these various benches. And as I’ve said before, the second bench really seems to have the same distribution and development as the first bench really. It’s very similar in character.

The third bench is a little thicker, but a little more shale. It has some anhydrite showing up in it. And so its distribution is equally widespread, but maybe quality of the reservoir might vary a bit. And then the fourth bench is more localized in this development. But we have a good handle on the distribution. Now the big question here is just how will it perform? And so, like I said, we’re drilling these wells to test really the commerciality, the productivity of these individual benches. And then once we do that, we can focus on how we proceed to head to development.

Noel Parks – Ladenburg Thalmann

Great.

Rick Bott

Let me add – could I add one – Noel, could I add one point to that?

Noel Parks – Ladenburg Thalmann

Please.

Rick Bott

I think that from an investor perspective, I think the key is to – I mean look at what we’ve done in efficiencies, in driving down our – or increasing our operational efficiencies. I think what you should expect from the Three Forks is that same sort of rapid application of our learning from everything we’ve done across the play in the Bakken to identify sweet spots, identify the high productivity areas. I think we will accelerate the devalue chain on the Three Forks and really bring that forward for us and understand the play a lot quicker because of all the knowledge that we built internally. That’s both on the geoscience side as well as on the operations side and the completion and stimulation.

Noel Parks – Ladenburg Thalmann

Great, that sounds great. I’d want to turn to the Cana Woodford for a moment. Have you permitted yet? Or even spud a long lateral well in the southeast part of the Cana yet?

Harold Hamm

We have not. That’s always possible and probable as we go forward. But we haven’t down here in this portion of the play.

Noel Parks – Ladenburg Thalmann

Okay. And then just a couple details I saw in the Q, I just wanted to ask about. One of them, I saw exploration expense was up a bit sequentially. Just wanted to check into that. And in the updated budget breakout that you give, I noticed that the capital facilities workover recompletions line looks like it was cut a bit. I mean it’s not huge in the overall scheme of things, but just to $70 million from $90 million. And I also saw that the – sort of the regular PP&E, vehicles, buildings there, looks like it has gone up a good bit. So any insight on that would be helpful.

John Hart

Certainly. The exploration expense, we had an incremental seismic during the quarter. It was primarily 3D shoots in the Southeast Cana that are going on in the second. You’ll have some of that in the third quarter as well. To your – ask me your second question again? Oh, the facilities? We’re simply running at a lower level year-to-date than we previously budgeted in that area. Forecasting out for the year, we’re expecting to spend less than previously estimated.

Noel Parks – Ladenburg Thalmann

Okay. That’s a good thing. And just the regular PP&E buildings, vehicles, I think it went from like about $6 million, the old number, to about $45 million?

John Hart

Yeah. There are a number of variables in there with the relocation, the building cost, the vehicles. Obviously, we do utilize other corporate assets going back and forth to our field locations. So you have some incremental spend in there. And some of it, to be frank, is just the classification of dollars where we’ve got those classified. There’s a little bit of a transition in some of those accounts.

Noel Parks – Ladenburg Thalmann

Oh, okay. Great. That’s all I had.

Operator

And your next question comes from the line of Eli Kantor with IBERIA Capital. Please proceed.

Eli Kantor – IBERIA Capital

Good morning, guys.

Harold Hamm

Good morning.

John Hart

Good morning.

Rick Bott

Morning.

Eli Kantor – IBERIA Capital

Was hoping you could walk us through the Cana lease expiration schedule. If gas prices remain on this depressed $2 to $4 range, what percentage of you guys’ 316,000 net acres do you expect to ultimately keep? What kind of rig activity would that require? And of the percentage that you expect to keep, how is that split between Northwest and Southeast?

Harold Hamm

We’re probably – the percentage is about 85% of this acreage in the Northwest that the company has decided to keep, and we’re actively renewing those leases as we speak. This is a high potential area. And it’s something that definitely, with higher gas prices, this works very well. So we’re committed to the area. We certainly think that it’s a very high potential area for the company and very good results, and we’re keeping approximately 85%. Some of the parts just to the east that’s just gas, we very well may not. But that’s only about 15%.

Eli Kantor – IBERIA Capital

What percentage in the Southeast?

Harold Hamm

We intend to keep it. We’re not letting any of that go, and those are longer-term leases as well.

Eli Kantor – IBERIA Capital

Okay. And how many rigs is that going to require to keep 85% in the Northwest and 100% in the Southeast?

Harold Hamm

As we renew these leases, of course, that gives us a longer runtime, and going forward, so you’re looking at three and a half, four year time span. And I don’t have the numbers, but it is increased considerably from where we’re at. So we’ve dialed down, we see – I see good things happening with natural gas as it comes back closer to $3 than $2. And of course, that’s an area worked good, a little bit higher than that, particularly in the oily areas that we’ve seen.

Eli Kantor – IBERIA Capital

Does your 85% estimate for the Northwest assume you start drilling that acreage again next year?

Rick Bott

No, it’s more – as Harold said, it’s more really a balance between drilling and holding it with lease renewals. So we’re just going to balance that out and do what’s pragmatic.

Eli Kantor – IBERIA Capital

Okay, great. Wanted to ask quickly on the Charlotte multi-zone assessment pilot when should we expect to hear results? And I apologize if I missed this, but when should we expect to hear results from the third bench and the first bench test? And what stages, if any, are you in, in drilling and completing those wells?

Jack Stark

We expect, as I said, to get our first third bench test spud late this month, following a permit hearing that’ll happen in the 22nd, I believe. And so we’re going to have 35 days to drill it and another 35 or so to get it completed and 30 days or so after that to put them on production, so we’re 90 days out from having some solid perspective on the performance of that well. And our second bench test there will be drilled immediately after that. So you’re dealing with probably 120 days before we’ll actually have some sustained production from both those wells to give you some perspective, but that’s where we’ll be.

Eli Kantor – IBERIA Capital

The well that immediately follows the third bench, for some reason I thought that was going to be a first bench test.

Jack Stark

It is.

Eli Kantor – IBERIA Capital

I –

Jack Stark

I’m sorry?

Eli Kantor – IBERIA Capital

Great.

Jack Stark

It is because we have a – we already have a second bench and a Middle Bakken producer there. And so we’re coming in and drilling a third bench test and that will be followed by a first bench. So this will be the first 1280 unit out here that actually has four well bores producing from four different members of the Bakken petroleum system here.

Eli Kantor – IBERIA Capital

Sure.

Jack Stark

So it’s a real key development.

Eli Kantor – IBERIA Capital

Sounds exciting. What kind of prices were you paying for Bakken and Cana acres in the second quarter?

Harold Hamm

We’ve – there have been some sales up here and I’ll let Steve address those. We’re seeing those prices continue to escalate.

Steve Owen

I mean, absolutely. We’ve – year-to-date, we’ve closed on six acquisitions – four in the Bakken and two in the Woodford. We’ve looked at probably 40 different opportunities that the prices just weren’t within our economic limit. Surprisingly enough, our success rate is higher with the private acquisitions just because we’re able to do a deal structure that works for both parties.

Eli Kantor – IBERIA Capital

Okay. In terms of the mid-year reserve report, what kind of EURs were assumed for PDPs and PUDs in the Bakken, and was there any change from year-end 2011 or mid-year 2011?

Rick Bott

There’s not really any change. I mean, I think we continue to see as – across the field, we see that average in that 603 MBoe number that we’ve used before. Some areas are a little bit better. Some areas are a little bit not quite so good – little bit higher water cuts. But I think, on average, that’s kind of a model that we’re still real comfortable with, and that’s essentially the driver for that mid-year review and will probably be the same for the end of the year.

Eli Kantor – IBERIA Capital

Okay. Great. Last question for me – one of your Williston peers has reported success in lowering their well costs by reducing the size of frac stages and the amount of proppant used on a per well basis in areas where the reservoir is shallower, the reservoir is thinner or there’s higher water saturation. Just wondering if you guys have looked at optimizing your completion design over the wide million net acres that you control.

Richard Muncrief

Boy, that’s a good question. We have – to answer your question, we have looked at that and we are still trying new things. In some of the areas where it is shallower, as you mentioned, we’ve had some sliding sleeve and smaller job type completions. We’ve had proppant plugs smaller job type completions where you’ve got water concerns. And so we’re going to continue to do that. And we do see variability in what we think is the optimum completion in the different areas. The other thing we’re doing is we’re tying in a lot of the core work that Jack mentioned earlier and really putting science into this – into our plans. And the luxury of having a widespread acreage gives us, gives a real – we think, a real clear idea of what that reservoir is going to do ultimately in the – both in the Bakken and in the several benches of the Three Forks.

Eli Kantor – IBERIA Capital

Great. Thanks very much for the color.

Harold Hamm

Yep.

Operator

And your next question comes from the line of Rudy Hokanson with Barrington Research. Please proceed.

Rudy Hokanson – Barrington Research

Thank you, gentlemen. Two questions. One, if you could talk a little bit about the variability on the differentials because your examples for the second quarter were all over the place, but the most recent looked very favorable and if you can give some kind of feel for that? And the second question is, as you’re still ramping up on your ECO-Pad drilling, one of the first cautions you had given was the possibility of lumpiness in terms of results because of the timing on completions of going to three or four at one time rather than being able to do each individual well sequentially. And I was wondering if you could give us some kind of color on what you see going forward with being at the number of rigs that you are now and how you plan to add them?

Rick Bott

Let’s take that second question first in terms of the smoothing out the lumpiness. I mean we will continue to carry an inventory of wells waiting to be completed as we move from pad to pad, but I think we’re able to manage that as we get more and more pad drilling out there. So we just have a larger portfolio from which to be able to make sure that we’re hooking up things. So I think it’s been smoother than we thought, I agree with you.

We’ve also had really good weather results and some of the things that could come back to bite you. So I think we’re still wary of that and we’ll keep that on your radar screen that is something that could be an issue. Maybe it just depends on exactly if you want pick an end of a quarter or end of a year, you may see a lot of that lumpiness. But if you’re just looking in terms of the overall production growth, it’s smoothing out considerably. On the differentials, let’s let Jeff talk about that because he’s negotiating those all the time.

Jeff Hume

Yes, Rudy, what we’ve seen in the past, since March on those differential blowouts was just a flood of oil that’s hitting both Clearbrook and Guernsey on the pipe and so that’s what’s been driving that. And we’re seeing that smooth out. And what happened, we had quite a few refineries down for turnaround. We had a lot of Canadian oil coming on. We had all the Syncrude’s units running. That’s smoothing out quite a bit now. We’re seeing stronger differentials at those pipes.

In addition to that, Enbridge is reversing its Line 9 up to Montreal. That’s going to be bringing in about 240,000 barrels of additional takeaway capacity and moving it up back across the Great Lakes and up to Montreal and into Canada working well.

The rail infrastructure continues to build out. We’re identifying many, many markets on the East and West Coast as well as the St. James market we’ve been participating in. And so I think you’ll see the overall trend of differentials coming down. Hopefully, we won’t see these spikes again. But it was just kind of a perfect storm, if you will, of production increases both in North Dakota. We have the pipelines full, so it wasn’t really an increase of that production, because we’re getting all we can to those markets. But mainly from Canada, a lot of it, the synthetic oil and they have a sweet, sweet oil growth up there also coming into a market that was constrained just due to refinery outages. So we’re seeing that being addressed and moving away, and we’re making more and more rail commitments to get that out short-term.

Long-term, there’s quite a few pipes. Rick talked about that earlier. We’re supporting quite a few pipes that are being built in there. We’ll see some expansion of Enbridge’s system back to Cromer in January. That’s going to take care of quite a bit of that.

We’ll also seeing an overall improvement in oil price the first of the year, when Seaway ramps up from 150,000 barrels a day to 400,000. That will take away that glut at Cushing. We’re seeing some draws at Cushing now so it’s – the capacity that’s in there now is helping. That’s going to work real well.

And then TransCanada announced they’re starting their Cushing to Houston leg. That’s probably going to be 14, 15 months out bringing that on. That will totally take away the differential on the WTI to the world price of the Brent or LLS price, which will give probably the biggest net gain to the field short-term. But we’ll be seeing improvement all along with that.

So I think that was an anomaly we saw. We’re pretty much behind that, and we should be seeing stronger and stronger prices going out in the future.

Rudy Hokanson – Barrington Research

Okay, thank you.

Operator

And your next question comes from the line of (inaudible) with Macquarie. Please proceed.

Unidentified Analyst

Thank you. Just wanted to clarify one item on the capital gains going forward for 2012. Does that include any effect from the increase in work inventories from the Wheatland transaction?

John Hart

We looked at a number of scenarios in assessing the capital guidance. And I think we’re adequately covered on a variety of scenarios. Obviously, that Wheatland transaction that you refer to has not closed yet. We don’t want to be presumptuous, although we are optimistic of a favorable outcome here in the near-term. And with that, it’s got a limited amount of months over the remainder of the year. So it really doesn’t have too – an overly significant impact on 2012.

Unidentified Analyst

Great, thank you. And then just turning to the capital structure quickly, obviously not a substantial amount of the revolver is drawn at this point in time, but as the outspend continues, is there a certain percentage at which you guys are comfortable up to in terms of having the revolver drawn where you’d look to potentially term out some of the revolver or what are kind of the thoughts on some of the funding going forward?

John Hart

When we speak to opportunities in funding, we look to a variety of scenarios. We’ve got an infinite number of ways to finance ourselves. And quite frankly, with rates where they’re at, we’ve got quite a bit of flexibility with the revolver. I’ve got the commitment set at $1.5 billion, but I could grow those all the way to $2.5 billion, and at 2% money, that’s not a bad deal. Terming out is something that we’ve done in the past. We look at markets continually. We always have that option.

Unidentified Analyst

Great. That’s all for me. Thank you.

Harold Hamm

Yeah.

Operator

And your next question comes from the line of Pearce Hammond with Simmons. Please proceed.

Pearce Hammond – Simmons

Thank you for taking my follow-up. I just wanted to get a little more color on comments that you made earlier on the non-consented wells in the Bakken. Was that a big problem in the first half of the year? And was it service costs that were really driving that problem or was it that patch where you hit a little bit lower oil prices back there in June?

Rick Bott

Well, it – thanks for revisiting that. I think it’s kind of hard to know what’s in another person’s mind, but we just assume that it’s really driven by oil price and driven by the fact that I think a lot of players are kind of late to realize what was going on there. And so a lot of people were really focusing on their operations because that’s where they can control it. And so when everyone’s trying to apply some capital discipline, you apply it where you have the most control. And so I think people chose to not participate and I think other people were really just kind of surprised by that and by the oil price.

And so for us, we looked at that and we also, on a number of opportunities that we did not think the economics were there based on the history of that operator, chose not to participate, really to send a message that we need to push those capital costs down and try to work with them to show them ways that we can get better results. Where that was successful, then we can participate in future wells; where it’s not successful, then it was probably the right decision.

But if you look at it as a whole, we looked at what operators were doing and we thought this is an opportunity for Continental. We’re a contrarian view sometimes and we thought in the wells we chose to participate in, we look at these a lot. And we thought these are good opportunities, these are great rate of return wells, and we would do them at that price. And so we chose to go ahead and do them and add what turned out to be a considerable growth in our net interest.

And it kind of goes to Harold’s visionary statements. I think he’s talked about last year is that this year will represent an opportunity for us to be the main consolidator in the Bakken. So it just fits right in with that theme in terms of how we want to continue to grow an asset that we think is the place to be in North America.

Pearce Hammond – Simmons

And are you seeing the non-consented wells continuing at all, and do you expect it to continue into the rest of the year?

Rick Bott

We are seeing it weekly. Yeah. And how long it continues in the future, I guess, probably depends on what’s driving those individuals to make those decisions. If it’s oil price, then, yeah, you may see it mitigate a little bit if we get a little bit better price in the third and fourth quarter. But we’re still seeing the same sort of trend on a weekly basis.

Pearce Hammond – Simmons

Thanks very much, Rick.

Harold Hamm

Thank you.

Rick Bott

Sure.

Operator

And your next question is coming from the line of Andrew Coleman of Raymond James. Please proceed.

Andrew Coleman – Raymond James

Hey. Thanks a lot and good morning, folks.

Harold Hamm

Good morning, Andrew.

John Hart

Good morning, Andrew.

Andrew Coleman – Raymond James

I just had a question. You’ve picked over a lot of the big topics here this morning. But as you look at your, I guess, SWD kind of capacity, how much is that a bottleneck right now going forward and I guess how much of the water disposal is going into Continental wells and Continental facilities?

Richard Muncrief

Yeah. The SWD is not an issue for us at all. We’re able to handle that quite easily. Unlike some of the other plays that are going on in the Lower 48, water handling is a huge issue. It is a consideration in the Bakken, but it’s really not – it’s not a big one.

Rick Bott

But I think, you have to brag on Rick’s team there a bit. I mean, these guys, they looked ahead at all of what the potential bottlenecks were and they made sure that didn’t become an issue for Continental. So it isn’t and it won’t be.

Andrew Coleman – Raymond James

Okay. All right, good deal. And then I guess stepping to the reserves here for a little bit. Your reserves I guess at year end last year were about 64% oil on the proved side, about 78% were oil on the PDP side. Looking at the replacement you guys talked about a couple weeks ago, where should we see those numbers trending to when you factor in the Bakken growth plus the Cana gas?

Harold Hamm

Yeah, that’s always a good question. As we look ahead and lay out our plan going forward, we’ve mentioned a couple plays that’s out there that’s going to change things and our view is oil is still where the value is and that’s where our focus is going to be and I wouldn’t expect that trend to reverse. I could expect that trend to reverse somewhat.

Andrew Coleman – Raymond James

Okay. And a final question is, thinking about your reserve report as well, do you have a PV-10 number mid-year that you could share or a standardized measure?

John Hart

Yeah, we don’t – we calculate those annually, and we don’t have that to disclose at this time.

Andrew Coleman – Raymond James

Okay. Well, thank you very much.

Operator

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

Subash Chandra – Jefferies

Yeah, just a couple follow-ups. As far as being a – the major consolidator in the basin, where do you see yourself given that opportunity. And I think we’re looking at acquisitions this year, is around $1 billion going to be the right number and what are you thinking of going forward?

Harold Hamm

Well, I think that overall up there in the play, that’s not going to exist forever. We’ve seen this consolidation kind of ramp-up and I think will be over maybe this year, first half of next year, I think that will be done. We generally crammed in upon the strategic areas that benefit us the most. The stuff that we know about, that’s right around us, consolidating our positions, is generally what we try to do. We’ve been very successful at that. We’re not going to get them all. As Steve said, we missed some of them. We don’t stretch far enough or somebody else does. But we’re, I think, the consolidator of choice up there, have been and maybe it’s the knowledge that we have of the play that benefited us in that.

Subash Chandra – Jefferies

And then on lease renewals, what are you offering land owners? Is it like herding cats and are you seeing the terms sort of vary quite a bit between landowners?

Steve Owen

Well, a lot of our oil and gas leases provide for options to extend when we originally took the leases, it’s a provision in the lease, and the prices are already set in the oil and gas leases. Our renewals seem to be trending the same or a little bit down. People understand the current environment and they want to work with Continental, they want Continental to be the operator, so we’ve had great success in very cost-effective renewals.

Rick Bott

I think the fundamental point there is exactly right. If you’re a leaseholder, what do you want? You want to get your well drilled, and you want to make as much money off of that as you can. So you want to go to the people who have got the fleet out there to drill it, and you want to go the low-cost operator.

So that’s – it’s good for us, it’s good for investors and it’s good for the leaseholder. And so it’s a win-win all the way around. And I think that we see people who on the whole really would much prefer to have Continental in there operating, as Steve has pointed out.

Subash Chandra – Jefferies

Okay. Thank you.

Rick Bott

Thank you.

Harold Hamm

Thank you.

Operator

And at this time, there are no further questions in queue. And I would now like to hand the call back over to Mr. Hamm for closing remarks.

Harold Hamm

Thank you very much. I appreciate each one of you joining us on our call today and, of course, would remind you, again, we’re holding our Investor Day on October 9 and hope that everybody can attend as we roll out our five- and ten-year plans, talk more on the Bakken, lower bench development, mention couple of crude oil stealth plays that we’re going to be talking a lot about at that time that we haven’t had the opportunity to do so right now because it’s still very competitive.

So going to be a lot to discuss as we change the organization and deal specifically with marketing focus up there. That’s a vast area, a lot of gains to be made – this differential, like Jeff mentioned, we’re able to erase that as we go forward. So thank you very much and we look forward to seeing you in October.

Operator

Ladies and gentlemen, that concludes today’s conference. Thank you for your participation. You may now disconnect. Have a wonderful day.

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