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Executives

Harold G. Hamm - Chairman and CEO

Winston Frederick Bott - President and COO

John D. Hart - SVP, CFO and Treasurer

Richard E. Muncrief - SVP of Operations.

Jack H. Stark - SVP of Exploration

Jeffery B. Hume - Vice Chairman of Strategic Growth Initiatives

Analysts

Leo Mariani - RBC Capital Markets

David Kistler - Simmons & Company

Doug Leggate - BofA Merrill Lynch

Brian Corales - Howard Weil

Rudy Hokanson - Barrington Research Associates, Inc.

Josh Silverstein - Deutsche Bank

Subash Chandra - Jefferies & Company

Hsulin Peng - Robert W. Baird & Co.

Noel Parks - Ladenburg Thalmann & Co.

Paul Gregory - Macquarie Research Equities

Continental Resources Group, Inc. (OTC:CRGC) Q1 2013 Earnings Conference Call May 9, 2013 10:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Continental Resources First Quarter 2013 Earnings Conference Call. This call is being recorded. Today’s call will include forward-looking statements that address projections, assumptions and guidance. 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.

In today’s call, the Company will refer to EBITDAX and adjusted net income per diluted share. For reconciliation of EBITDAX to GAAP net income and operating cash flows and for a reconciliation of adjusted net income per diluted share to GAAP net income per diluted share, please refer to the section non-GAAP financial measures in the first quarter earnings press release, which is posted on the Company’s website at www.CLR.com.

Mr. Harold Hamm, Chairman and CEO, will begin this mornings call; followed by President and COO, Rick Bott; and Chief Financial Officer, John Hart. After their remarks, we'll have the question-and-answer period. Other members of management are available to answer your questions.

And now, I will turn the call over to Mr. Hamm.

Harold G. Hamm

Good morning, everyone and thank you for joining us this morning. Continental reported excellent results yesterday afternoon. Our first quarter performance demonstrated the key strengths that set Continental apart as a leading E&P operator. Strong production growth focused on oil. Continental is on track with 35% to 40% total production growth in 2013, partly results from our exploration programs. We’re demonstrating productivity in the lower Three Forks formations across the Bakken. We launched our 47 well density program and we’re derisking and extending the SCOOP play here in Oklahoma.

Lower well cost, we’re in privilege of drilling and completion operation, maximizing markets through oil and gas marketing, including increased access to coastal markets for a premium Bakken crude oil and keeping transportation costs low. And finally spending discipline. We intend to maintain our focus on capital discipline throughout the year, and our CapEx budget of $3.6 billion.

Let’s go straight to the first quarter’s accomplishments in each of these areas with Rick and John and I will wrap up prior to beginning of Q&A periods. Rick.

Winston Frederick Bott

Thanks, Harold. Let me take each of Harold’s points he mentioned in order. First of all, production growth is the first big headline for the quarter. We achieved record net production of 121,500 barrels of oil equivalent in the first quarter, 42% increase over the first quarter of last year and 14% higher than the fourth quarter of 2012.

Crude oil accounted for 71% of first quarter 2013 production, slightly ahead of plan for the quarter. If we include NGL, we estimate our total liquids production was 80% of total production. The Bakken continues to lead the way in the first quarter. Bakken net production was up 60% year-over-year and 14% higher than the fourth quarter. In the Bakken we benefited from strong well results on multiple ECO-Pad projects.

Last quarter, we mentioned the Florida-Alpha project, where we completed six wells on a pad for less than $8 million per well. IPs on the Florida-Alpha wells were amongst the strongest in the quarter with average test production of almost 1,600 barrels of oil equivalent per well over the 24-hour test periods. At a cost of less than $8 million each these well should generate tremendous rates of return.

Our two strongest Bakken wells in the quarter were in the Angus area, the Angus 3-9H and the Angus 2-9H-2 with peak production test rates of approximately 2,200 and 2,100 barrels of oil equivalent per day respectively. The Angus 3 is a middle Bakken well and the Angus 2 is a second bench producer. The Angus 2 was originally announced in the late February with an IP rate of 1,556 barrels of oil equivalent per day. Production subsequently strengthened to 2,100 barrels of oil per day upon further clean up of the well.

In SCOOP we doubled net production compared with the fourth quarter of 2012 increasing to approximately 14,250 barrels of oil equivalent in the first quarter. This total was about 5.5 times the SCOOP production in the first quarter of 2012 and up 100% over fourth quarter 2012, reflecting increased positive completion results.

We continue to generate strong well results in SCOOP and we’re excited about the outlook for this emerging play. We will increase operated rig count in the SCOOP faster than originally planned and we’re currently operating nine rigs ahead of plan and expect to increase to 12 rigs by early third quarter instead of by the end of the year.

Note that this accelerated rig deployment involves no increase in capital expenditure. We’re benefiting from the efficiencies we’ve gained in the Bakken and adjusting our projects to absorb this acceleration within the current budget. We are confident we will meet our 2012 production goal of 35% to 40% production growth as Harold mentioned.

Secondly, we’re seeing very positive results from exploration, both in Bakken and SCOOP. In the Bakken we announced three new lower bench Three Fork wells, two new second bench wells and one additional third bench well.

Let’s start with the second bench well. The Barney 2-29H-2 was a significant step out success located in Williams County, 16 miles north of the Charlotte and McKenzie County. The Barney had a 24-hour initial production rate of approximately 1,100 barrels of oil equivalent per day. The Stedman 2-24H-2 was another significant second bench step out also in Williams County, but located 35 miles Northwest of the Charlotte union – unit. The Stedman 2-24H-2 had initial production rate of 1,030 barrels of oil equivalent per day.

Finally the new third bench well, the Stedman 3-24H-3 IP’d at approximately 465 barrels of oil equivalent per day. This is an important validation of the extend of the third bench productivity as its located almost in Montana and its performing in line with Montana Middle Bakken well. It fits our geologic model and that is acting completely independent of the second bench well in the same area.

With solid results like these were proving the prospectivity of the lower Three Forks benches over a broad area. Our plan is to complete a total of 20 lower bench wells in this year and divide Dunn, McKenzie and Williams Counties as part of the large scale productivity testing program.

Our second major exploratory initiative in the Bakken involves four density pilot projects, three in – 320-acre spacing and one is a 160-acre spacing. Combining these projects will involve 47 wells completed in the Middle Bakken, Three Forks one, Three Forks two and Three Forks three benches. Two 320-acre density pilots are underway. The Hawkinson project in Dunn County was the first to spud and it has eight wells in various stages of completion and the final three wells in drilling.

The Tangsrud 320-acre pilot in Divide County has two wells completing and five drilling. The final 320-acre pilot the Rollefstad project in McKenzie County is expected to commence in late summer. The Wahpeton 160-acre density pilot has commenced in McKenzie County with two wells drilling.

We expect to report results from these density pilots quarterly, when all wells in each project are completed, starting with the Hawkinson later this year and the final ones in the first half of 2014. We encourage to see other operators following Continental’s lead in conducting density and down spacing tests. We are aware of at least eight additional density pilots being conducted by others. The whole industry will benefit from more well control to help derisk this play.

Finally, we’re excited about exploratory success we’re seeing as we extend the SCOOP play in Oklahoma. We participate in completing nine net SCOOP wells since the beginning of the year with results in line with our expectations for the play. We listed a couple of these wells in their 24-hour IP rates in our quarterly press release, the Colbert at 1,769 barrels equivalent per day and the Knox at 1,151 barrels of oil equivalent per day.

The third headline that Harold discussed is lower completion well costs. We are driving down Bakken well cost with the combined effects of faster drilling cycle times, more ECO-Pad projects and completion efficiencies. We are also seeing faster cycle times and lower completion costs in the SCOOP area as well. Last October we set a goal of reducing average operated Bakken Well cost $8.2 million by year-end representing a 10% savings from the $9.2 million in 2012.

As of today, we’re about six months ahead of schedule to accomplish our year-end target in the Bakken. Based on field reports, we believe our current average cost is $8.3 million per operated well for April wells. The Bakken team is obviously doing a great job. These well cost savings from improving efficiencies will allow us to drop two Bakken rigs and still hit our production targets for the year.

In SCOOP we set a goal of reducing cost by $500,000 per operated well by year-end 2013 and we’re on track for this goal. We produced spud cycle times approximately 25% in SCOOP from a range of 55 to 60 days in the first half of the year to about 42 to 44 days currently. We continue to focus on achieving these cost reduction targets to deliver capital efficiency.

The fourth headline is maximizing margins to oil and gas marketing efforts. We continue to use a portfolio approach in marketing using both rail and pipelines to move oil out of the Bakken and SCOOP. First quarter average oil differential was $4.29 per barrel, below and favorable to our 2013 guidance range of $5 to $7 for the year.

In the first quarter approximately 80% of our operated Bakken wells were railed out of the basin. Recently we’ve seen a narrowing of the Brent WTI spread, which is bringing the rail option into rough parity with pipeline alternatives. Our task is to retain marketing flexibility and optionality in terms of future commitments. If Brent WTI spreads continue to converge, we will look at pipeline evacuation opportunities and we’ll need to see rail carriers reduce their costs to stay competitive.

We’ve also begin to diversify how we sell our oil, balancing spot selling with short-term agreements to commit set volumes of oil to specific refining customers. On the natural gas side, our first quarter differential was a positive dollar -- $65 per Mcf, better than our guidance range for the year. Again, reflecting the liquids rich content of our gas production.

We continue to work with midstream vendors to assure the gas takeaway and processing infrastructure is available as we bring new production online in our two key operating areas. Harold will have more to say about this in his comments.

And the final headline of course is spending discipline. We are managing operations to stay within the 2013 capital budget. We want to bring forward as much value as possible from our oil and liquids rich drilling inventory, while at the same time maintaining financial flexibility and a strong balance sheet.

First quarter non-acquisition CapEx of $899 million was in line with our 2013 budget and reflects a number of dynamic factors. First quarter’s spending included a substantial work down of the completions that we deferred from the fourth quarter of 2012. Of the 80 net well completions in the quarter, 21 involved deferred completions from late ’12. This backlog will fluctuate throughout the year depending on the amount of pad drilling in any given quarter.

The other key dynamics involved improving cycle times and overall lower well cost as we mentioned previously. The key takeaway is we expect to remain on budget and in fact plan to achieve our production guidance while operating fewer drilling rigs in the Bakken.

Summarizing, Continental’s team performed at a very high level in the first quarter of 2013 and I want to thank them for it. As Harold said, we are very much on track to make or exceed our goals for the year.

Now let me turn it over to John Hart. John?

John D. Hart

Thanks, Rick. I’d like to provide some color on Continental’s financial strength as it relates to our growth plans. Adjusted net income for the first quarter was a $1.17 per diluted share, beating the Street consensus. We continue to increase EBITDAX in the first quarter of ’13 as well. This time to a record $622 million, up 37% from the first quarter last year and 5% above the fourth quarter of 2012. First quarter EBITDAX was $21 million higher than Street consensus estimates.

Our cash margin was 74% for the first quarter as compared with 73% for 2012 as a whole. Once again, we confirmed Continental has a high margin, high growth leader among our oil concentrated peers. Continued growth of our cash flow stream is critical. Our five-year plan to a triple production and reserves, while manning top tier debt metrics.

We support the stability of cash flow growth with a prudent hedging strategy. Our March 31 hedge position is laid out in the Form 10-Q which we filed last night. Approximately 61% of our 2013 expected oil production is hedged, against the WTI average price of $93 and another 14% of our production is hedged against a Brent average of $109. At the end of the first quarter we had approximately 91% of our expected 2013 natural gas production for the remainder of the year, hedged against a Henry Hub price of $3.78 per Mcf.

Another strategic focus is to capitalize on the strength of our balance sheet to generate additional liquidity. In early April he completed a highly successful $1.5 billion, 4.5% senior unsecured notes offering, which is due in 2023. Part of the proceeds were used to pay down the balance on our revolver, so we now have a fully undrawn $1.5 billion facility and several hundred million in cash.

As of March 31, long-term debt was $4 billion. So our net debt to EBITDAX ratio was 1.8 times on a trailing 12 months basis. Looking at on the first quarter annualized it would be 1.6 times EBITDAX. We expect cash flow to continue increasing as production ramps up through the year and as we continue to reduce well cost.

Finally, in terms of our overall guidance on the year, the first quarter’s results are consistent with our 2013 Outlook as provided at the end of February. First quarter 2013 production expense was $5.70 per Boe, a $0.20 improvement compared with the $5.90 in the fourth quarter, but slightly ahead of our guidance of $5.20 to $5.60 for the full-year 2013. This is not a concern since production expense typically peaks in the winter months and then trends down through the second, third and early fourth quarters.

Now I’d like to turn the call back over to Harold.

Harold G. Hamm

Thank you, John. At Continental we have the enjoyable task of reporting strong results quarter after quarter to investors who for the most part are familiar with the story and have invested with us for many years. In the past several months however volatility in oil prices have attracted quite a few new investors who recognize the buying opportunity, but were less familiar with us.

To you new investors joining us today, let me say that 2013 first quarter was textbook Continental Resources. Solid execution and focus on fundamentals this is how we judge our self and expect to judged quarter after quarter, year after year. This is how we’ve earned our investors confidence and how we plan to create long-term value for all of our shareholders. So I will bolt it down to four concepts, the first one of those is growth. Continental is a growth Company with an unmatched oil and liquids rich drilling inventory that will support decades of industry leading growth. We’re the leading leaseholder, driller and producer in the Bakken the cornerstone of America’s movement towards energy independence. We are a growth Company.

Exploration, we are explorationists, always looking for the next unconventional geologic concept, the next opportunity to apply advanced horizontal drilling completion methods to produce American energy. In the Bakken even as we’re transitioning into full development mode, we’re exploring the depths of the play, expanding production in the lower Three Forks benches and pushing out the Bakken geographic margins.

Continental was the first mover in realizing the potential of Middle Bakken as unconventional oil reservoir, then in 2008 when the Middle Bakken became conventional wisdom, we were the first to target depth of benches at Three Forks. Today based on our coring studies and exploratory drilling we’re discovering the lower benches of the Three Forks, testing well densities and configuration to prepare for full development of the entire Bakken oil system. We are an exploration Company.

Third, we focus intently on margins and operating excellence. Value creation is driven as much by operating excellence as it is by premier assets. Let me say that again, value creation is driven as much by operating excellence as it is by premier assets. We faced challenges as a team of professionals dedicated to getting better constantly. We work at a high level and tough environments like North Dakota in the winter and despite these challenges we are constantly striving to improve our performance quarter after quarter.

Challenges are opportunities for leadership. Take oil marketing as an example. 15 months ago differential blew out when there wasn’t sufficient pipeline capacity to get Bakken oil out of the basin. Production is simply growing too fast for the system. Continental and one or two others saw the opportunity to rail oil to the Gulf Coast refineries bypassing the pipeline system and the (indiscernible) at Cushing. But Continental alone recognized the opportunity of rail Bakken oil to the East and West Coast refinery complexes and now we are expanding markets on both coasts that weren't even accessible from the Bakken in the recent past.

Operating excellence is demonstrated by our commitment to keep reducing well cost as Rick and John mentioned, but also by our commitment to protecting our people and being good stewards of the environment. We hold ourselves to exceptional standards, especially with regards to the health and safety of our employees and contractors and with regard to the overall environment that we operate in.

We are the industry leader in reducing flaring in North Dakota. Of the last 24 Bakken oil completion, 23 had gas [gathering] lines in place and ready to go in the first day of production. This type of green completion is standard operating procedure at Continental requiring high degree of coordination with main stream companies and the State Regulatory Agencies as well as lot of hard work with landowners to gain pipeline access on a timely basis.

Operating excellence represents much more than do it faster for less cost. Our teams are committed to working with vendors, contractors and regulators to working more safely and getting better to fundamentals of energy exploration and production.

Finally the fourth key trait that that defines Continental as financial discipline. Of course we seek to lead in efficiency, witness our 74% cash margin in the first quarter and in constantly pushing the technical limits for drilling and completing wells in less time for less cost. Beyond higher margin operations however, we have developed a strategic hedging program as John described, to stabilize cash flow and support our long-term growth plan.

Finally as we discussed, each quarter we are disciplined in the management of our balance sheet, a strong balance sheet is fundamental to long-term growth and value creation. This is Continental, an exceptional growth Company, constantly exploring for new opportunities, create value and operating at a high level with a strong financial foundation. Our ultimate goal is exceptional value creation for the people of Continental and for you who invest your confidence in us. We thank you for your support and look forward to reporting additional achievements to you through the remainder of this year.

With that, I’d like to turn the call back over to our operator and we will be glad to taking questions you might have. Thank you very much.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Your first question comes from the line of Leo Mariani of RBC. Please proceed sir.

Leo Mariani - RBC Capital Markets

(Indiscernible) your production doubled this quarter from the previous quarter, which clearly is pretty impressive here. Just trying to get a sense of whether or not maybe some of the wells in 2012 were constrained, I mean, I know you brought nine net wells on which didn't seem to be enough wells to me to double production. So, I am just trying to get a sense of what was going on previously there and whether or not there are any still constraints there in the play and how you see infrastructure developing?

Richard E. Muncrief

Yeah Leo, this is Rich Muncrief. The infrastructure build out has been underway and our gathering companies are doing a relatively good job of keeping up with those work in conjunction with them on getting our wells drilled and completed. We are seeing some nice results and I think that showed up in the production numbers where we continue to see those that results in the next quarter as well.

Leo Mariani - RBC Capital Markets

So, I guess, did you have historical constraints on infrastructure and that alleviated at this point or would you just got to continue the build out and you guys are just bringing production on as the build out happens?

Richard E. Muncrief

We did have some constraints in the fourth quarter last year. But we worked through that relatively quickly and easily.

Leo Mariani - RBC Capital Markets

Okay. I guess, just jumping over to the Bakken here, I guess, there has been some chatter of some of random flooding and weather events in North Dakota, obviously you got spring break-up. Are you guys seeing any impact on your operations thus far in 2Q and any expectations for that this quarter?

Richard E. Muncrief

Well, we – it’s been a – that’s a fairly typical winter in North Dakota. In the last year we had a nice winter and in some cases that was some of the first winters that many of the operators had really worked in the Bakken. Continental on the other hand has been – up there for a long time, for decades and so we understand how to operate. We do – we did see some impacts and even today we’re seeing some small impacts with some frost laws, but we’re managing through that and don’t think its going to be impacting us materially in a negative sense.

Leo Mariani - RBC Capital Markets

Okay. That's helpful. And I guess, in terms of Three Forks, you obviously had good step out success, one well, 16 miles from the Charlotte, one well 35 miles away. Obviously, you had a good result earlier in the week from EOG as well. I mean how are you guys thinking about the Three Forks second bench on your acreage? Is it feasible to think of it in terms of how much you think has been de-risked for the second bench at this point? Would you guys be able to ballpark quantify that?

Winston Frederick Bott

Well, I will tell you Leo, its – we’re very encouraged with our results and the results of others out here. There is – I think there is about six additional wells out there that have been tested in the second bench along with ours. And so we’re starting to see the footprint really of productivity in the second bench started to expand very quickly. And as we’ve mentioned before, the first and second benches really are fairly uniformly developed across the basin which just gives us confidence in the – the early extent of the play or expanding the play in the second bench of the Three Forks. So, I think that the results we have are really starting to substantiate, are substantiating our expectations for the second bench out here.

Leo Mariani - RBC Capital Markets

All right. Thanks a lot, guys.

Harold G. Hamm

Thank you.

Winston Frederick Bott

Thank you, Leo.

Operator

Thank you. Your second question comes from the line of Dave Kistler of Simmons Comp. Please proceed.

David Kistler - Simmons & Company

Good morning, guys.

Harold G. Hamm

Good morning.

Winston Frederick Bott

Good morning.

David Kistler - Simmons & Company

Real quickly one kind of housekeeping item, in the past you guys have given us current production levels as you release your quarterly results. Can you share that with us this morning?

Winston Frederick Bott

Yeah Dave, we’re at approximately 130,000 barrels a day equivalent.

David Kistler - Simmons & Company

Okay. That’s helpful. I appreciate that. And then focusing on the decline in well costs, obviously very close to hitting your target for the year early on, do you think about increasing that target and seeing well costs drop even further or was Q1 specifically skewed to more pad drilling that has influenced that cost?

Winston Frederick Bott

I think once again the pad drilling is a big impact and we have 70% of the rigs on pads. It really start showing up and we did see some preliminary costs coming in, last quarter that really made us feel that we were getting the good start on our goals. However, just only recently here we gotten to the point we had enough aging with our costs and we feel confident to make the announcement we did. So, we will continue, we will always continue to look at driving down cost, doing it the right way, right size of cost structure and so we will reevaluate where we’re at, but right now we will stick with the numbers that we laid out.

David Kistler - Simmons & Company

Okay. I appreciate that.

Harold G. Hamm

If I can add in terms of – just in terms of re-forecasting, it's probably little too early at this point. And some of the – we’re confident in the costs as Rick talked about for where we operate, and how that’s going to translate for the rest of the year. Some of them non-op and we’re in quite a number of non-op wells where we haven’t seen the cost savings really there that others have talked about or hinted at. And so, we’re looking forward to that coming through. If that does translate, then we might be in a position to reforecast, but at this point in time we’re not re-forecasting, we will stay – sticking with our original guidance.

David Kistler - Simmons & Company

Okay. I appreciate that. One last one, just to the third bench, kind of thinking about the comments of your increased confidence and how the second bench has been de-risked when you look at in that obviously much smaller subset of results, but when you look at the results on the third bench wells, how do you think about geologically where you’re today and what that looks like versus kind of the broader estimates you guys gave us at the Analyst Day in terms of what kind of opportunity set you saw in the third bench?

Jack H. Stark

The third bench, I mean, really what we’re seeing right now is we’ve got – we’ve two completions at this point in the third bench. So its really early to make some broad conclusions about where what we’re going to see of the Three Forks three here, but our second test here came out with 465 barrels a day and that is modest compared to our original, our first completion at the Charlotte that came out for 953 barrels of oil equivalent a day and Charlotte wells producing very nicely. It’s done about 55,000 barrels in its first [5.5] months of production. So it looks real strong and so the contrast between the outcomes there suggests that we’re seeing at least between those two wells as 35 miles between them.

Stedman is out here on the Montana border that as you go out to the west and head towards the edge of the basin, we’re starting to maybe see the reservoir quality of the third bench vary – become a little more variable and that fits our geologic model. We anticipated that more centrally located in basin you’re going to see more continuity in the third bench and as you move out to the flanks, you start picking up some more end [hydrides] and you get some things that basically degrade the quality of the reservoir in some areas. So, actually what we’re seeing is kind of in line with our expectations initially here and so – I will also mention, too something very significant here is that in the Stedman section, we drilled and reported that we completed the second bench and a third bench test this quarter.

Well, those two wells are 3,300 feet apart. And the interesting thing is the contrast in the productivity from the second bench versus the third bench. And if you look at the second bench, it came on for 1,030 barrels a day; the third bench came on for 465. Well that contrast there I think directly indicates that we’re looking at wells that are performing differently and the reason they’re performing differently is because these reservoir rocks are acting independently and that’s one of the things we’ve been trying to prove. One thing on our 22 rig or exploration well program out here is to demonstrate the extent of the productivity of these zones, but the other is to demonstrate that we’ve incremental resource from these individual second, third and four benches to the overall play.

So, the significance of the difference in production there to me is that we’re seeing that these layers are acting as independent reservoirs. Now we need to continue to work this into build more evidence of that, but that’s another thing, it’s our model for this – these lower benches. So, we’re very – things are really kind of developing along the lines of our original expectations out here and we’ll continue to keep you posted. We are about – got about 30% of our wells that we got planned on production. About 40% in our exploration program in the completion phase and then we got about 30% more that obviously to drill, but we’ll just continue to deliver results to you as we go here. You’re basically in this exploration program with us here. We are kind of giving you the play by play as we go, but I really think we’ve got some really good outcomes here.

Harold G. Hamm

Dave, let me add one point. If I could add one point to that, from the beginning we invited you guys to look at this as a program and we said there will be some variability in results and be some variability across areas. And so we’re reporting that variability as we go along, but as Jack said its still those fit our model and as your question – your final question is how does it impact the overall resource potential that we talked about in our Analyst Day? We’re still pretty excited that we’re on track to realize within that range. So we’re pretty upbeat about these deeper benches.

Jack H. Stark

Yeah, I might add the distance I just going to mention one other thing, that just to keep in perspective, these wells are very far – they’re spaced very far apart. I mean, the northern most wells to the southern most wells is 80 miles and the east to west is about 50 miles. So, the footprint that we’re demonstrating here, these tests are providing remarkably similar results given the widespread nature of the location. So that’s another very encouraging point for the play.

David Kistler - Simmons & Company

Well great, guys. I certainly appreciate those clarifications.

Operator

Thank you. Your next question comes from the line of Doug Leggate of Bank of America. Please proceed.

Doug Leggate - BofA Merrill Lynch

Thanks. Good morning, guys. I guess, I’ve got a couple of follow-ups on the Three Forks. I'm kind of trying to understand the relative economics of Three Forks versus, particularly, on the Montana side of the Bakken and what I'm really trying to get at is, assuming the Three Forks delineation and exploration program works out as predicted, how would you think about reallocating your rig program between the Montana and the Bakken side in terms of attacking the deeper and perhaps more economic Three Forks? And I have got a couple of follow-ups, please.

Winston Frederick Bott

I think its – that’s a good question. I think with only the limited number of tests we’ve at this point in time, I don’t think its really – its not the appropriate time to talk about reallocation where our rigs are going to be going. I think at the end of the day, we’ll focus on the highest rate of return projects and make sure that we will bring in those forward.

Doug Leggate - BofA Merrill Lynch

Okay. So towards the end of the year, I guess, but my point is would you look to move the rig count up or reallocate within the portfolio?

Winston Frederick Bott

Oh, current plan is to reallocate within the portfolio.

Doug Leggate - BofA Merrill Lynch

Okay, great. I guess, thinking the similar kind of question, the costs you’ve given us on the targets for the year for the well costs in the Bakken, how are the costs – I realize it’s exploration obviously, but how are the costs in the deeper – the Three Forks sections comparing to the base line targets you have? I imagine they are a little higher given the exploration mode, but what do you think on a run rate basis the incremental would be?

Jack H. Stark

Doug the run rate or the incremental costs for these deeper benches, remember we’re not talking that much deeper from a TVD standpoint. It’s virtually the same cost.

Doug Leggate - BofA Merrill Lynch

Okay. And my final question, I guess, this one is for John. John, you mentioned the hedging program and the percentage of TI versus Brent hedging, I guess, but it seems to us or what have been told, the refiners are saying, that you’re leading the charge and moving quick through the course. So I'm just kind of curious as to, from a marketing standpoint, how do you expect your benchmark oil prices to evolve? I mean, currently you’re, I guess, about 60% hedged against TI, but do you expect that to move to increasingly more towards Brent-type realizations? In your Brent minus transportation obviously, and I will leave it at that. Thanks.

John D. Hart

It has moved – our hedging program certainly has moved more towards Brent. The WTI positions in ’13 we put on, in some cases two years ago and other cases more narrow. We begin shifting more to a balance in the stronger orientation towards the Brent. So as you move in to ’14 Brent is larger than WTI in terms of our total hedge portfolio. That shifts, the markets are going to shift from month to month, it shifts from the amount of rail, the amount of pipeline and I think that flexibility between those two will continue to be in place. So we attempt to be adaptive in the – in our hedging approach and to the instruments that we’re using.

Doug Leggate - BofA Merrill Lynch

John is it kind of a Brent minus pricing that you’re getting right now and if so, can you tell us what the transportation cost is?

John D. Hart

We don’t speak to our transportation cost. You certainly see plenty of others that are out there with their views of transportation costs to different markets, that’s a very competitive market and we’re leader in that market. So it’s something that is proprietary to us. However, in – give me your initial part of your question again.

Doug Leggate - BofA Merrill Lynch

Well I was really just trying to understand what proportion of your production is going to end up being linked to Brent relative to more localized TI over time?

John D. Hart

Yeah, I think that as we access these coastal markets and continue to where like you said, work out for Brent price minus transportation in those part.

Winston Frederick Bott

Doug, let me add one point however. You have to sort of take off the blinders in terms of what benchmark the Bakken sells for, because I don’t know sometime this summer or third quarter Bakken total basin production will exceed the entire 40s Brent basket in terms of the volumes of production. And so as we’ve talked about before, essentially the Bakken will when it gets to 1 million to 1.5 million barrels a day, the Bakken will essentially be kind of that North American benchmark.

Doug Leggate - BofA Merrill Lynch

Understood. I will leave it there, guys. Thanks very much.

Winston Frederick Bott

Yes.

Operator

Thank you. The next question comes from the line of Brian Corales with Howard Weil. Please proceed.

Brian Corales - Howard Weil

Congratulations, guys. Couple of questions primarily on the SCOOP. You kind of average 25% oil, is that just on the kind of the light condensate side or is that how you all drilled this quarter, is that going to increase going forward? Can you maybe elaborate a little bit?

Winston Frederick Bott

Yeah, it has to do with the particular thorough fair where we’re HBPing our acreage. And that really is just driven by the timing of when we acquired that acreage and when we need to make sure we HBP it. So if you remember we talked about consistent results within a band of the condensate fairway and consistent results within the oil thorough fair. So we invite you to compare them within fairways, but not really across fairways and so the amount of oil in there is really having to do with which fairway that well was in and that’s driven really by our HBP.

Brian Corales - Howard Weil

Okay, no, that’s helpful.

Jack H. Stark

I was just going to mention the fact that in Q1, our focus – we did focus in the condensate window for leasehold considerations and so all of our drilling and all the reports that we have are really from wells in the condensate window.

Brian Corales - Howard Weil

Okay. And how much of that 230,000 acres has been – do you think has been derisked today?

Harold G. Hamm

We haven’t – we didn’t put a number on it as such, but we got production pretty much through the extent of it. So, I don’t know, we can get back with you on that number. We’re probably about guessing and that’s what we’re doing right at this moment. It would be about half of it.

Brian Corales - Howard Weil

Okay. And then great job on the well costs in the Bakken, can you talk about what the average well or what a well – how many wells a rig can drill each year now that most of your rigs are on pads?

Jack H. Stark

Brian, that’s – that is going to range from probably in the 14 – plus or minus 14 to 15 wells per year. If you look at just the last – and just to give you a sense of cycle time improvement on our – from a year-ago, Q1 of ’12 to Q1 of ’13 25% improvement on spud to TD, 28% improvement in our days in the lateral, 22% of improvement in vertical days, 33% average footage per day and cost per foot about 28%. So, when you start looking at that, and we look at our rig releases, the first quarter of 2012 we had 25 rigs running and we had 66 rig releases in the first quarter of this year with only 22 rigs running we had 71 rig releases. So, I think it really speaks the efficiencies.

Brian Corales - Howard Weil

So could we see even further drop in further rigs maybe in the second half?

Jack H. Stark

I think that the 20 rig count is about where we need to be to and remember we’re going to be looking at most of our – the bulk of our rig count is on pads and so they’re going to be there a while.

Brian Corales - Howard Weil

Okay. All right, guys. Thank you.

Harold G. Hamm

Thank you.

Operator

Thank you. The next question comes from the line of Rudy Hokanson of Barrington Research. Please proceed.

Rudy Hokanson - Barrington Research Associates, Inc.

Good morning.

Harold G. Hamm

Good morning.

Rudy Hokanson - Barrington Research Associates, Inc.

A couple of clarifications or maybe a little bit more on the questions that you already have been answering. One on the number of rigs that are on pads, do you see that percentage going up much or because of your current program do you see it staying at about, I believe it's 70%?

Winston Frederick Bott

Well, that’s a good question. Let me say it this way. We are balancing two side of the table. Jack’s side of the table, who is expanding and extending the play and Rick’s side of the table, which is driving those efficiencies. So its really going to fluctuate in terms of what we’ve out there in terms of new ideas we want to test, continue to HBP our acreage, we will continue in the Bakken. Acreage that we’ve added, we’ve added acreage and continue to add acreage and then that balance of moving to full scale production. So, I’d say for 2013 expected to continue and to fluctuate, but its going to be in around in that range of plus or minus 5% on pads.

Rudy Hokanson - Barrington Research Associates, Inc.

Okay. Thank you. And then I was just wondering – and I know this is hard to call, but do you see the progress on the lower bench programs and in terms of when you will be having different wells coming on production or being completed, et cetera. Do you see that as being fairly even over the next three quarters as far as when you discuss them? Should we expect about the same number each quarter or do you see perhaps that the bulk of it might be done by the end of the third quarter?

Jack H. Stark

I think that we’ll have these done by the end of the year and so we’re going to have each quarter, we’re going to have probably as you have said about the same number of wells we reported each quarter. Its like I said, we had at this point, lets say we got as I recall, we got what seven wells that are completing right now, seven to be drilled and two are drilling as you can see in our press release there. And so we’re – we get 30% of more producing, we got another 70% to get completed and on line. So – but we have all those reported here by year-end, wouldn’t you say Rick?

Richard E. Muncrief

Yeah, year-end of first quarter.

Rudy Hokanson - Barrington Research Associates, Inc.

Okay. Thank you. Those are my questions.

Jack H. Stark

Thank you.

Winston Frederick Bott

And Rudy one last point, now no one has asked it, but we do have a couple of fourth bench wells in the program as we talked about and it is in our press release. And those unfortunately haven’t been released yet, some of them are still completing because they’re on pads and it is just taking a bit longer.

Rudy Hokanson - Barrington Research Associates, Inc.

Okay. Thank you, very much, Rick.

Operator

Thank you. The next question comes from the line of Ryan Todd of Deutsche Bank. Please proceed.

Josh Silverstein - Deutsche Bank

This is actually Josh Silverstein for Ryan here. Just wanted to go back to some of the marketing and rail questions from before, of the 80% that you guys are saying you’re moving on rail, I was curious if there was a percentage that’s actually going direct to the refinery versus kind of the spot market and shippers?

Harold G. Hamm

We are not putting any barrels to spot market on shippers, it’s all going to refinery clients at the other end. So, we’re not using middle marketing. We make our own market with the refiners at the various coasts.

Josh Silverstein - Deutsche Bank

Got you. Okay and then when you talk about the flexibility and the short-term nature of the contracts, are these week to week or month to month and what’s – if there are longer term contracts within there, is there an ability to terminate those quickly or how can you guys kind of increase the flexibility within there to take advantage of the spreads?

Harold G. Hamm

Well, there is just so much you can do right now. You can switch some from the rail back to pipe, and think that’s what you’re alluding to, but there is a limited amount of pipe today that will be begin to go away in about 12 months from now when the pipes from the region move out. Back to your original question on the length – the term of our contracts, we don’t discuss our commercial terms, but for the most of the part where we’ve any term that are staggered, so we cant step out of these fairly quickly and we stay fairly nimble on that.

Josh Silverstein - Deutsche Bank

Got you. Okay. That was it for me. Thank you.

Harold G. Hamm

Thank you.

Operator

Thank you. The next question comes from the line of Subash Chandra of Jefferies. Please proceed.

Harold G. Hamm

Good morning, Subash.

Subash Chandra - Jefferies & Company

Hey, good morning.

Harold G. Hamm

I think you’re on.

Subash Chandra - Jefferies & Company

Yeah, can you hear me?

Winston Frederick Bott

Yes, fine.

Subash Chandra - Jefferies & Company

Oh, sorry about that. Good morning. Can you repeat how many Bakken completions you had this quarter?

Winston Frederick Bott

Yes.

Richard E. Muncrief

It’s in our release.

Subash Chandra - Jefferies & Company

I wasn't sure if that was wells drilled or wells completed?

Richard E. Muncrief

It should have been – 66.

Jack H. Stark

Yeah, 66.

Richard E. Muncrief

Right, 66 wells were completed and to give you a little color there, we had – we did have a backlog of completions to do coming out of the fourth quarter as you recall we employed some discipline on our CapEx and we made sure that we stayed within our budget last year and doing so we had to back off some of our completions. So went from a five completion through operation in the Bakken to three in the fourth quarter. In the first quarter we started catching up and peaked at six completion crews through most of the quarter, that’s why that the account was as it was.

Subash Chandra - Jefferies & Company

Got you. Okay. In SCOOP, two questions there. One is, are you drilling – have you eliminated a string of casing there and second, what is sort of the range of costs you’re experiencing?

Richard E. Muncrief

Well, currently we’ve not eliminated. We still have our casing string, it typically will be intermediate and then we’ll drill out from underneath the intermediate to down kick-off point and then drill our lateral from 5.5 or back to surface. And the range that we’ve seen thus far on a completed well cost have been in the 8.5 million to I think the high-end was 10.5 million on those well with some mechanical issues were with, but 8.5 million has been where we’ve been thus far on a one mile lateral. We are in the process of completing our first two mile lateral down there, about half way through on the completion and next quarter we should have some results there. We don’t have [handful] more of two mile wells to drill.

Subash Chandra - Jefferies & Company

What are the impediments to removing a string there? Do you think that just won’t be achievable or something that you will work on eventually?

Richard E. Muncrief

Well, I need to understand what string you’re talking about removing.

Subash Chandra - Jefferies & Company

So you said, the intermediate. I think a competitor has said they’re – they got two strings running through. They eliminated one, saving about $0.5 million and I think they also suggested that they might have switch to different mud-based system, I suspect oil-to-water to save even some more money per completion. So I was curious if any of that’s relevant to your experience?

Richard E. Muncrief

We’ve not changed the casing design at this point.

Subash Chandra - Jefferies & Company

Okay. Next question is in the Lower Three Forks. Have you done micro seismic yet on any of these wells or [with your] plans?

Winston Frederick Bott

Here our plan is part of these large down spacing pilots to look at with micro seismic and confirm and/or develop new models in terms of where the fracs are going. So yes, there are plans. We haven’t start any of those yet. They’re in some of these programs that are just getting started.

Subash Chandra - Jefferies & Company

Okay, great. Thanks, guys.

Winston Frederick Bott

Thank you.

Operator

Thank you. The next question comes from the line of Hsulin Peng. Please proceed.

Hsulin Peng - Robert W. Baird & Co.

Good morning. This is Hsulin Peng from Robert Baird. So my question is regarding PET drilling. I was wondering if you can talk about the number of wells that you generally complete at one-time for PET drilling such that you can size the appropriate gathering line to make sure production gets into the pipe.

Richard E. Muncrief

We work in conjunction with our gathering companies and very seldom will we have the wells or pads bringing on that we have long-term impacts from the ability to take all the gas, minimize flaring. In some cases, we do have situations arise where we have to pinch our wells back, not flow at the maximum capability to minimize flaring. And that’s something that’s extremely high on our list.

Winston Frederick Bott

That’s a kind of a may be at max a quarterly impact. I think the Midstream companies have been good at like coming in there and understanding that looping lines, adding compression where they need to, to make sure that we’re able to get that backed up. So it’s not a major material issue. It’s something that’s kind of worked at a field level between our operations guys, our marketing crew, logistics guys and then the Midstream partner whoever that might be.

Hsulin Peng - Robert W. Baird & Co.

Okay. So you don’t really have to choke too much production back just to make – for the capacity of the pipe?

Richard E. Muncrief

No it’s not materially, no.

Winston Frederick Bott

Not usually and the way we do that is essentially we know how many wells we’re going to drill, how long the rigs are going to be there, how many we’re going to drill and what we expect to get out of that when we sit down and talk to the Midstream partners and as we’ve said and Harold mentioned, we still lead the industry because we don’t necessarily drill an area if we don’t have that hooked up and so that we make sure we minimize that flaring and environmental impact as a result of it. So, that’s kind of our go, no-go area and we’ve got so much acreage and so much activity that we can move around rigs and reschedule as we need to lift them if the Midstream partners got some delays in a particular area. But we haven’t, it’s not a real material impact.

Hsulin Peng - Robert W. Baird & Co.

Okay, got it. And then my second question is regarding the acceleration of wells in the SCOOP area, now that you are drilling 55 from the 41 net wells before. That's – I mean, if it’s calling that around $9.5 million well cost, it’s around $130 million costs increase, but obviously you’re not increasing your ’13 CapEx. So I was wondering if you’re anticipating more cost reduction in the SCOOP area or do you anticipate allocating some capital from elsewhere?

Richard E. Muncrief

We are anticipating and we’re starting to see that the cost reductions in the SCOOP area.

Winston Frederick Bott

And as we said in our note, we’re reallocating. So we’re sticking with the net budget. The savings that we’re getting from the efficiencies in the Bakken are being translated into both our key areas.

Hsulin Peng - Robert W. Baird & Co.

Okay. And then – so with the additional wells, both in the SCOOP and the Bakken, it seems like there potentially is upward values in your ’13 production guidance, Is that …?

Winston Frederick Bott

Well, we’re in May, we are sticking within our range. I think we try to – we model a range around our mid-point, which is a stochastic analysis of what we think those wells are going to get. So, I think that’s kind of up to you guys to determine whether or not it will be the high end or low of that, but we’re saying that range is still a good number to guide to.

Hsulin Peng - Robert W. Baird & Co.

Okay. Thank you. That’s my questions.

Harold G. Hamm

Thank you.

Operator

Thank you. The next question comes from the line of Noel Parks of Ladenburg Thalmann. Please proceed.

Noel Parks - Ladenburg Thalmann & Co.

Can you hear me?

Richard E. Muncrief

Yes, we can.

Winston Frederick Bott

Yes, we can. Go ahead, Noel.

Noel Parks - Ladenburg Thalmann & Co.

Great. The – my first question, I guess, thinking about the SCOOP, we had fortunately some improvement in dry gas prices over the last couple of months or so. Compared to your thinking earlier in the year, has that sort of affected, I guess, the pace that you’re going to pursue the SCOOP at, as you look in the rest of the year and into next year?

Winston Frederick Bott

Well, I wouldn’t say it’s due to natural gas prices. I think it’s due to the what the rocks are telling us. So, we’re bullish about the area. We’re HBPing a acreage that’s what’s driving this schedule that we have now and we’re pleased with the results. Yes, we’re gaining a little bit higher margin out of that as result of the gas prices, so that’s good news for us. But it’s not necessarily the driver for activity. It’s really what the rocks are telling us.

Noel Parks - Ladenburg Thalmann & Co.

Sure. Sure. And along the same lines, we’ve seen a little strengthening in gas, we've seen NGLs continue to struggle. Maybe the question that would be as you look at the different product mix and different parts of the SCOOP, or different parts of the region, does that have an effect on sort of what part of your acreage you might be most aggressive on earliest?

Winston Frederick Bott

No, not really. Again, it’s that HBP schedule. When we acquired the acreage and when we need to make sure we drill it in geologically, what is – what area do we need to drill and to answer the appropriate questions to help us derisk and/or bring that value forward with a full field development plan. So that’s really the goal here. I’d suppose you need a considerably higher movement in gas prices or NGLs for us to change that significantly.

Noel Parks - Ladenburg Thalmann & Co.

Okay. So, essentially the product mix at this stage just isn’t really material to the plans?

Winston Frederick Bott

Correct.

Noel Parks - Ladenburg Thalmann & Co.

Got you. And moving to the Bakken for a second, you talked a lot about the Three Forks, the deeper benches, and just what you’re seeing across it. As I look to sort of trying to model the additional upside you might see from the lower benches. If you move across the basin, is there any variability as to the chances for communication between the different benches or is that something that just geologically is going to be pretty consistent. In other words, do you still have any questions out there about communication between the benches?

Jack H. Stark

Well Noel, it’s a good question, and that’s part of our process here to our exploration program is to define just those types of basically confirm those questions. We – like I said we want to demonstrate number one, productivity and we’re doing that on a widespread basis. We’ve already expanded it out to all the way to the Montana border at this point, showing that the second, third benches produce that far. And so the next step obviously is we want to confirm and we’re in the process of doing that, while the additional drilling we’re doing here that is there are these incremental reserves that we’re getting or these zones communicating. And as I mentioned earlier, we’re encouraged with the results we’re seeing at this point saying that we’re seeing these zones evidence that they’re acting independently. And then the other thing is that we’re really kind of just going to – with these type of – with the inventory that we’ve got out here of opportunities, we’ll just continue to do the tests and monitor increased densities that we’re drilling and combine that with these step outs that we’re doing in this exploratory program to really come up with a conclusion and in the next 12 months we hope to have some ideas on, some confidence in what we’re seeing out there. We were confident about the outcomes that we’re seeing at this point, but we need to just get some more evidence, all right?

Noel Parks - Ladenburg Thalmann & Co.

Great. And sorry if you – I'm not sure if you commented on this already today, but compared to the Charlotte wells, your earliest ones to the lower benches, how – can you just remind us what the 30 and 60 day IPs look like in those – in the Charlotte wells? And then for, I guess, the earliest of your most recent set, how they’re performing relative to that early curve?

Winston Frederick Bott

Noel, what we should do is, I think that’s in our press release in terms of what, how much total volume, so you can divide that by days. So we will work that out and get it back to you.

Noel Parks - Ladenburg Thalmann & Co.

Right. I think you give June oil production for the whole – yeah, for the life of the well. So yes, I was just kind of curious about the early days. So, yeah, if someone can get back me, that would be great.

Winston Frederick Bott

Yeah, I think the headline there that you’re looking for, the headline is that those wells are very much in line with what our expectations were, very much in line with the Middle Bakken and the Three Forks one in that area. And also remember these are all a stochastic range around our average model, our 603 model, it’s a little bit different over Montana. So that’s they’re within that range and they’re still holding up and sort of fitting that trend.

Noel Parks - Ladenburg Thalmann & Co.

Thanks. Just what I was looking for. That's it for me.

Winston Frederick Bott

So, I just make one point though in an effort to keep our call around an hour and respect all the other companies reporting today, we will take two more questions.

Operator

Thank you. The next question comes from the line of Eli Kantor of IBERIA Capital Partners. Please proceed.

Winston Frederick Bott

Eli?

Harold G. Hamm

Eli, are you there? Let’s go ahead and take the next one.

Operator

The next question comes from the line of Paul Gregory of Macquarie. Please proceed.

Paul Gregory - Macquarie Research Equities

Hi. Good morning. Actually at your Analyst Day back in October, you spoke to increasing rig count to 50 in 2014. Given some of the efficiencies you’ve seen and the discussion on capital discipline, how should we be thinking about the capital plan beyond 2013?

Winston Frederick Bott

Great question. We’ve taken a look at that right now and remodeling these efficiencies that we’ve seen into our five-year plan. So, it may be exactly as Rick Muncrief sort of alluded to there earlier that we’ll need fewer rigs over the entire development to achieve what we want to do in terms of production.

Paul Gregory - Macquarie Research Equities

And but broadly, the capital amount would stay fairly constant at that point in time?

Winston Frederick Bott

That’s right. I think that’s kind of our plan is to keep that capital in a reasonable line and stay within those debt metrics that we’ve guided to.

Paul Gregory - Macquarie Research Equities

Okay. And just following up on that, previously you guys have made comments about accelerating activity at higher oil prices, generally above $95 for WTI. Is that something that’s still possible this year or should we view it as $3.6 as prefixed?

Winston Frederick Bott

We don’t have any intention to stepping it up. We’re going to stay within our capital guidance and stay with our budget.

Paul Gregory - Macquarie Research Equities

Okay. And then lastly, just touching on the take-away capacity issues, what kind of pipeline availability is there? I think Rick touched on it just briefly saying it may go away over the next 12 months. But if you were to have rail economics be no longer advantageous, what pipeline capacity could you step into?

Harold G. Hamm

I want to talk first of all to overall capacity and then I will let Jeff talk to the pipeline capacity. One thing that people may, I hope everybody has got the understanding of this that what rail has done up here basically eliminate the overall capacity constraints. I mean that’s been the great thing about it, if you can ship everything you produce, so the overall capacity constraints has been relieved. Jeff, you want to talk about the pipeline?

Jeffery B. Hume

Yeah, on the overall pipeline capacity starting next fall we’ll see capacities start opening up, the Pony Express line will come on going to the east, probably before that we’ll see Enbridge expanding their system to move oil out of Clearbrook, up their line nine, which will feed the Great Lakes area. That’s going to improve that market and I think probably start to swing some of the barrels to the east. And then after that we’ve additional capacity expansion that we’ll be bringing it out of the Bakken on pipe. And then, what you’re going to see though is the rail as Harold spoke is well built out and we’re seeing every day, this morning there was another announcement on refiner building rail receipt points. So the refiners are going to compete for the barrel, they’re going to have a rail transportation component. The folks on the pipe are going to have a pipe transportation component. We’re going to have a flux for the next year and a half or so, which mark as the best. We’re going to try to position our barrels in the best market. But in the end game, you’re going to see these come close, come into parity and you’re going to have good transportation to the all three coasts and the mid-continent with a combination of rail and pipe and are going to [equilibrate] to a reasonable price and they’re going to have to do that or the barrels will flow because there will be enough capacity within two years to move huge amount of barrels out by pipe as well as by rail. So, some flux for the next 18 months and then we’ll see more stabilized pricing on the differential front, yeah.

Paul Gregory - Macquarie Research Equities

Great, thank you.

Operator

Thank you. I’d now like to turn the call over to Mr. Harold Hamm for closing remarks.

Harold G. Hamm

Thank you today for everybody for your questions and for joining us and we look forward to talking to you next quarter.

Operator

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

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