Continental Resources Management Discusses Q1 2013 Results - Earnings Call Transcript

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Continental Resources (NYSE:CLR)

Q1 2013 Earnings Call

May 09, 2013 10:00 am ET

Executives

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

Winston Frederick Bott - President and Chief Operating Officer

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

Richard E. Muncrief - Senior Vice President of Operations

Jack H. Stark - Senior Vice President of Exploration

Jeffery B. Hume - Vice Chairman of Strategic Growth Initiatives

Analysts

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

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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

Rudolf A. Hokanson - Barrington Research Associates, Inc., Research Division

Josh Silverstein - Deutsche Bank AG, Research Division

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

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

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

Paul Grigel - Macquarie Research

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 a 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 morning's call; followed by President and COO, Rick Bott; and CFO, John Hart. After their remarks, we will have a question-and-answer period. Other members of the management are available to answer questions.

And now, I'll turn the call over to Mr. Hamm. Please go ahead, sir.

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 the leading E&P operator.

Strong production growth focused on oil. Continental is on track to 35% to 40% total production growth in 2013. Positive results from our exploration programs. We're demonstrating productivity in the Lower Three Forks formations across the Bakken. We launched our 47-well pilot density program, and we are de-risking and extending the SCOOP right here in Oklahoma.

Oil well cost. We're improving both drilling and completion operation, maximizing margins through oil and gas marketing, including increased access to coastal markets for 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, then I'll wrap up prior to the beginning of our Q&A period. Rick?

Winston Frederick Bott

Thanks, Harold. Let me take each of Harold's points he just 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, a 42% increase over the first quarter of last year and a 14% higher -- 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 NGLs, 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, which -- where we completed 6 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 wells should generate tremendous rates of return.

Our 2 strongest Bakken wells in the quarter were the -- 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 late February with an IP rate of 1,556 barrels of oil equivalent per day, but production subsequently strengthened to 2,100 barrels of oil per day upon further cleanup 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 5.5x 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 are currently operating 9 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're 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 3 new lower bench Three Forks wells, 2 new second bench wells and 1 additional third bench well.

Let's start with the second bench wells. The Barney 2-29H-2 is a significant step-out success located in Williams County, 16 miles north of the Charlotte in 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-ed at approximately 465 barrels of oil equivalent per day. This is an important validation of the extent of the third bench productivity, as it's located almost in Montana, and is performing in line with Montana Middle Bakken wells. It fits our geologic model in that it is acting completely independent of a second bench well in the same area.

With solid results like these, we are 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 in Divide, Dunn, McKinsey and Williams Counties as part of the large-scale productivity testing program.

Our second major exploratory initiative in the Bakken involves 4 density pilot projects: 3 in 320-acre spacings and 1 is a 160-acre spacing. Combined, these projects will involve 47 wells completed in the Middle Bakken, Three Forks 1, Three Forks 2 and Three Forks 3 benches.

Two 320-acre density pilots are underway. The Hawkinson project in Dunn County was the first to spud, and it has 8 wells in various stages of completion and the final 3 wells in drilling. The Tangsrud 320-acre pilot in Divide County has 2 wells completing and 5 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 2 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 are encouraged to see other operators following Continental's lead in conducting density and downspacing tests. We're aware of at least 8 additional density pilots being conducted by others. The whole industry will benefit from more well control to help de-risk this play.

Finally, we're excited about the exploratory success we're seeing as we extend the SCOOP play in Oklahoma. We participate in completing 9 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 and 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 cost. We're driving down Bakken well costs with the combined effects of faster drilling cycle times, more ECO-Pad projects and completion efficiencies. We're 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 to $8.2 million by year-end, representing a 10% savings from the $9.2 million in 2012. As of today, we're about 6 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 2 Bakken rigs and still hit our production targets for the year.

In SCOOP, we set a goal of reducing costs by $500,000 per operating well by year-end 2013, and we're on track for this goal. We produce spud-to-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 lead the capital efficiency.

The fourth headline is maximizing margins through 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 have also began 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 $1.65 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 that gas takeaway and processing infrastructure is available as we bring new production online in our 2 key operating areas. Harold will have more to say about this in his comments.

And the final headline, of course, is spending discipline. We're 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 flexibly 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 spending included a substantial work-down at 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've mentioned previously.

A 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're 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 streak as it relates to our growth plans.

Adjusted net income for the first quarter was $1.17 per diluted share, beating the Street consensus.

We continued to increase the 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 as a high-margin, high-growth leader among our oil concentrated peers.

Continued growth of our cash flow stream is critical. Our 5-year plan to triple production and reserves while maining 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 the 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, we 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 1.8x on a trailing 12 months basis. Looking at it on the first quarter, annualized, it would be 1.6x 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. In Continental we have the enjoyable task of reporting strong results quarter after quarter to investors, who, for the most part, are familiar with our 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's first quarter was textbook Continental Resources. Solid execution and focus on fundamentals, this is how we judge ourselves and expect to be 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 it boils down to 4 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 acquire 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's geographic margins.

Continental was the first mover in realizing the potential of Middle Bakken as an unconventional oil reservoir. Then in 2008, when the Middle Bakken became conventional wisdom, we were the first to target out the benches in 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 the 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 is by premier assets.

We face challenges, but as a team of professionals dedicated to getting better constantly, we work at a high-level in tough environments, like North Dakota in the winter, and despite these challenges, we're 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 has simply grown too fast for the system. Continental and 1 or 2 others saw the opportunity to rail oil to Gulf Coast refineries, bypassing the pipeline system and the glut at Cushing. But Continental alone recognized the opportunity to rail Bakken oil to the East and West Coast refinery complexes, and now, we're 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 oil 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 regard to the health and safety of our employees and contractors and with regard to the overall environment that we operate in.

We're the industry leader in reducing flaring in North Dakota. Of the last 24 Bakken well completion, 23 had gas gathering lines in place and ready to go on the first day of production. This type of green completion is standard operating procedure at Continental requiring high degree of coordination with midstream companies and state regulatory agencies, as well as a 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 at the fundamentals of energy exploration and production.

Finally, the fourth key trait that defines Continental is financial discipline. Of course, we seek to lead in efficiency, with [indiscernible] 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 high-margin operations, however, we've 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 were 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 to create value and operating at a high-level with a strong financial foundation. Our ultimate goal is exceptional value creation for the people at 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 would be glad to take any questions you might have. Thank you very much.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Leo Mariani of RBC.

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

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 9 net wells on, which didn't seem to be enough wells for me to double the production. So I'm 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

Yes, Leo, this is Rick Muncrief. The infrastructure buildout has been underway, and our gathering companies are doing a relatively good job of keeping up with us. We're working 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. We will continue to see those nice results next quarter as well.

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

All right. So I mean, I guess, did you have historical constraints on infrastructure? And is that alleviated at this point, or you're just going to have to continue the buildout and you guys are just bringing production on as the buildout happens?

Richard E. Muncrief

We did have some constraints in the fourth quarter of last year, but we'd work through that relatively quickly and easily.

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

Okay. I guess, just jumping over to the Bakken here, I guess, there's just been some chatter of some random flooding and weather events in North Dakota. Obviously, you got spring break up. 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 -- I'd say, a fairly typical winter in North Dakota. 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 walls, but we're managing through that. And I don't think it's going to be impacting us materially in a negative sense.

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

Okay. That's helpful. And I guess, in terms of the Three Forks, you obviously, had good step-out success, 1 well, 60 miles into Charlotte; 1 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? I mean, is it feasible to think of it in terms of how much is going to be de-risked for the second bench at this point, would you guys be able to ballpark quantify that?

Jack H. Stark

Well, I'll tell you, Leo, it's -- we're very encouraged with our results and the results of others out here. There's -- I think there's about 6 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 starting to expand very quickly. And as Rick mentioned before, the first and second bench is really -- fairly uniformly developed across the basin, which is -- gives us confidence in the early extent of the play. We're expanding the play in a second bench in the Three Forks. So I think that the results we have are really starting to substantiate or are substantiating our expectations for the second bench out here.

Operator

Your second question comes from the line of Dave Kistler of Simmons Comp.

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

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?

John D. Hart

Yes, Dave, we're at approximately 130,000 barrels a day equivalent.

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

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

John D. Hart

Well, I think once again, the pad drilling is a big impact, and when you have 70% of your rigs on pads, it really starts showing up. And we did see some preliminary cost coming in last quarter that really made us feel that we were getting a good start on our goal. However, just only recently here we got to the point where we've had enough aging with our cost and we feel just confident to make the announcement we did. So -- but we'll continue -- we'll always continue to look at driving down cost, doing it the right way, rightsize our cost structure. And so we'll reevaluate where we're at. But right now, I think that we'll stick with the numbers that we've laid out.

Winston Frederick Bott

If I can add in terms of -- just in terms reforecasting it, it's probably a little too early at this point. And some of the -- we're confident in the cost, as Rick talked about, for where we operate and how that's going to translate for the rest of the year. Some of the non-off -- and we're in quite a number of non-off 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. And if that does translate, then we might be in a position to reforecast, but at this point in time, we're not reforecasting. We're sticking with our original guidance.

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

Okay. I appreciate that. One last one, just to the third bench, kind of thinking about the comments of your increased confidence in how the second bench has been de-risked. When you look at -- and the 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 are 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

Sure. The third bench -- I mean, really what we're seeing right now is we've got -- we have 2 completions at this point in the third bench. So it's really early to make some broad conclusions about where -- what we're going to see out of the Three Forks 3 here. But our second test here came on for 465 barrels a day, and that is modest compared to our original -- our first completion at the Charlotte that came on for 953 barrels of oil equivalent a day. And Charlotte well is 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 suggest that what we're seeing, at least between those 2 wells, is -- 35 miles between them, the 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 the 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 anhydrite and some -- 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'll also mention to you something very significant here is that in the Stedman section, we've drilled and reported that we completed the second bench and a third bench test this quarter. Well, those 2 wells are 3,300 feet apart. And the interesting thing is the contrast in the productivity for the second bench versus the third bench. And if you look at the second bench, you see it came on for 1,030 barrels a day, the third bench came on for 4,065. 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 -- our exploration well program out here is to demonstrate the extent of the productivity of these zones. But the other is to demonstrate that we have incremental reserves from these individual second, third and fourth benches to the overall play. So the significance of the difference in production there, to me, is that we are seeing that these layers are acting as independent reservoirs. Now we need to continue to work this and to build more evidence of that. But that's -- another thing, it fits our model for these lower benches. So things are really kind of developing along the lines of our original expectations out here. And we'll continue to keep you posted. We're -- we got about 30% of our wells that we've got planned on production and about 40% in our exploration program in the completion phase and then we've got about 30% more, 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're kind of giving you the play-by-play as we go, but I really think we've got some really good outcomes here.

Winston Frederick Bott

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'll be some variability in results, there'll be some variability across areas, and so we're reporting that variability as we go along. But as Jack said, it still does fit our model. And as to 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

The distance -- I'm just going to mention one other thing that just to keep in perspective, these wells are very far -- spaced very far apart. I mean, the northernmost wells to the southernmost wells is 80 miles and then -- and 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.

Operator

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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

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 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've got a couple of follow-ups for you.

Winston Frederick Bott

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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Okay. And so before the end of this year, I guess -- but, I mean, I guess, 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.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

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

Richard E. Muncrief

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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

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, listening to what the refiners are saying that you are leading the charge in moving crude to 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 from -- currently you're, I guess, about 60% hedged against TI. But do you expect that to move increasingly more towards Brent-type realizations, and I'll -- in your Brent minus transportation, obviously. And I'll leave it at that.

John D. Hart

Okay. It has -- our hedging program certainly has moved more towards Brent. The WTI positions in '13 would put on -- in some cases, 2 years ago; In other cases, more narrow. We began shifting more to a balance in a stronger orientation towards the Brent. So as you move into '14, Brent is larger than WTI in terms of our total hedge portfolio. That shifts -- the markets you're going to shifts from month-to-month. It shifts from the amount of rail, the amount of pipeline. And I think that flexibility between those 2 will continue to be in place. So we attempt to be adaptive in our hedging approach and to the instruments that we're using.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

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 costs. You certainly see plenty of others that are out there with their views of transportation cost to different markets, that's a very competitive market, and we are a leader in that market. So it's something that is proprietary to us. However -- give me the initial part of your question again?

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

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

Jeffery B. Hume

Yes, I think that as we access these coastal markets and continue to -- we're -- like you said, work out for Brent price minus transportation for the most 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, some time this summer, at 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.

Operator

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

Brian M. Corales - Howard Weil Incorporated, Research Division

A couple of questions, primarily on the SCOOP. You kind of averaged 25% oil. Is that just going to kind of the light condensate side? 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

Yes, it has to do with the particular thoroughfare where we are HBP-ing our acreage, and that really is just driven by the timing of when we acquire 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 thoroughfare. 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.

Jack H. Stark

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And how much of that 230,000 acres has been -- do you think has been de-risked today?

Harold G. Hamm

We haven't put a number on it as such, but we've got production at pretty much through the extent of it, so I don't know, we can get back with you on that number. We're probably -- if I was guessing, and that's what we're doing right this moment, would be about 1/2 of it.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then great job on the well cost 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 the -- your rigs are on pads?

Richard E. Muncrief

Brian, 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 -- just to give you a sense of the cycle time improvement on our -- from a year ago, Q1 '12 to Q1 of '13, 25% improvement of spud to TD, 28% improvement in our days in the lateral, 22% improvement in vertical days, 33% average footage per day and the cost per foot by 28%. So when you start looking at that, and we look at our rig releases, the first quarter of 2012, we had -- with 25 rigs running, 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 to the efficiencies.

Brian M. Corales - Howard Weil Incorporated, Research Division

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

Richard E. Muncrief

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 awhile.

Operator

The next question comes from the line of Rudy Hokanson of Barrington Research.

Rudolf A. Hokanson - Barrington Research Associates, Inc., Research Division

A couple of clarifications or maybe a little bit more on the questions that you've already 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're balancing 2 sides of the table. Jack's side of the table, who's expanding and extending the play, and Rick's side of the table, which is driving those efficiencies. So it's really going to fluctuate in terms of what we have out there in terms of new ideas we want to test; continue to HBP our acreage, we'll 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, expect it to continue to fluctuate. But it's going to be in around in that range of plus or minus 5% on pads.

Rudolf A. Hokanson - Barrington Research Associates, Inc., Research Division

Okay. 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'll be having different wells coming on production or being completed, et cetera? Do you see that as being fairly even over the next 3 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

Well, 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 report each quarter. It -- like I said, we had -- at this point, I'd say we've got -- as I recall, we've got, what, 7 wells that we're completing right now, 7 to be drilled and 2 that we are drilling, as you can see in our press release there. And so, we're -- 30% of them are producing; we've got another 70% to get completed and online. And so -- but we'll have all those reported here by year-end. Would you say, Rick?

Richard E. Muncrief

Year-end, first quarter, you bet.

Winston Frederick Bott

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

Operator

The next question comes from the line of Ryan Todd of Deutsche Bank.

Josh Silverstein - Deutsche Bank AG, Research Division

It's 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 to shippers?

Richard E. Muncrief

We're 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 as to refiners at the various coasts.

Josh Silverstein - Deutsche Bank AG, Research Division

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?

Richard E. Muncrief

Well, there's just so much you can do right now. You can switch some from the rail back to pipe. And I think that's what you're alluding to, but there's 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 part, where we have any term, they're staggered, so we can step out of these fairly quickly, and we stay fairly nimble on that.

Operator

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

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

Can you repeat how many Bakken completions you had this quarter?

Harold G. Hamm

Yes.

Richard E. Muncrief

Yes, it's in our release. Let's see.

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

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

Richard E. Muncrief

It should've been [indiscernible] I believe, there was 6 -- let's see, 66.

John D. Hart

Yes.

Harold G. Hamm

66.

Richard E. Muncrief

You're right. 66 wells that 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 in doing so, we had to back off some of our completions. So we went from a 5 completion crew operation in the Bakken to 3 in the fourth quarter. In the first quarter, we started catching up and peak that to 6 completion crews through most of the quarter, so that's why that rig count was -- is high as it was.

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

Got you. Okay. In SCOOP, 2 questions there. One is, are you drilling -- have you eliminated the string casing there? And second, what is the sort of the range of cost you're experiencing?

Richard E. Muncrief

Well, currently, we have not eliminated. We still have our casing string. Typically, we'll be intermediate, and then we'll drill out intermediate down to kickoff point and then drill our lateral, run $5.5 million all the way 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 most wells with these mechanical issues were -- we have. But $8.5 million has been -- where we've been thus far on a 1-mile lateral. We are in the process of completing our first 2-mile lateral down there, about halfway through on the completion. And next quarter, we should have some results there. We're going to have handful more of 2-mile wells to drill.

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

And what are the impediments to removing a string there? Do you think that just won't be achievable or something that you'll work on eventually?

Richard E. Muncrief

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

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

So it said, the intermediate. I think a competitor has said they're -- they've got 2 strings running through. They eliminated 1, saving about $0.5 million. And I think they also suggested that they might switch to different mud base system, I suspect, oil to water to save even some more money for completion. So I was curious if any of that is relevant to your experience.

Richard E. Muncrief

We have not changed the casing design at this point.

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

Okay. Next question is, in the Lower Three Forks, have you done microseismic yet on any of these wells or are there plans?

Winston Frederick Bott

There are plans as part of these large downspacing pilots to look at with microseismic and confirm and/or develop new models in terms of where the fracs are going. So yes, there are plans. We haven't started in any of those yet. They're in some of these programs that are just getting started.

Operator

Your next question comes from the line of Hsulin Peng.

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

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

Richard E. Muncrief

Yes, 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 a -- situations arise where we have to pinch our wells back, not flow it to maximum capability to minimize flaring. And that's something that's extremely high on our list.

Winston Frederick Bott

That's kind of a -- maybe a max, a quarterly impact. I think the midstream companies have been good at coming in there and understanding that looping lines, adding compression where they need to, to make sure that we're able to get that back up. So it's not a major material issue. It's something that's kind of worked at the 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. Incorporated, Research Division

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 -- 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 rig is 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 sort of lead the industry because we don't necessarily drill an area if we don't have that hooked up. And so that we can 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 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. Incorporated, Research Division

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

John D. Hart

We are anticipating, and we're starting to see the cost reduction to the SCOOP area.

Winston Frederick Bott

And as we said in our note, we are reallocating, so we're sticking within that 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. Incorporated, Research Division

Okay. And then -- so with the additional wells in the SCOOP and the Bakken, it seems like there potentially is upward bias in your '13 production guidance? Is that correct?

Winston Frederick Bott

Well, we're in May, we're sticking within our range. I think we try to -- we model our range around our midpoint, 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 we'll be at the high end or low of that, but we're saying that, that range is still a good number to guide to.

Operator

The next question comes from the line of Noel Parks with Ladenburg Thalmann.

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

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 into 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 what the rocks are telling us. So we're bullish about the area. We're HBP-ing any acreage. That's what's driving the schedule that we have now, and we're pleased with the results. Yes, we're getting a little bit higher margin out of that as a 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 A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

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

Winston Frederick Bott

No, not really. Again, it's that HBP schedule, when we acquire the acreage and when we need to make sure we drill it and geologically what is -- what area do we need to drill in to answer the appropriate questions to help us de-risk and/or bring that value forward with a fulfilled development plan. So that's really the goal here. I would suppose you need a considerably higher movement in gas prices or NGLs for us to change that significantly.

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

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

Winston Frederick Bott

Correct.

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

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 lower benches, as you move across the basin, is there any variability after 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 -- and basically to confirm those questions. We -- like I said, we want to demonstrate, #1, 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 out that far. And so, the next step, obviously, is we want to confirm, and we're in the process of doing that with the additional drilling we're doing here. That is there -- are these incremental reserves that we're getting or are these zones communicating, and as I've 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 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 test and monitor, increase densities that we're doing and combine that with these step-outs that we're doing in this exploratory program to really come up with a conclusion. In the next 12 months, we hope to have some ideas and some confidence in what we're seeing out there. We're confident about the outcomes that we've seen at this point. But we need to just get some more evidence. All right?

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

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 sort of 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, where -- how did it perform relative to sort of that early curve?

Winston Frederick Bott

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

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

Right, yes. I think you gave [indiscernible] production for the whole -- yes, for the life of the well. We just were kind of curious what the early days, so -- yes, if someone would get back to me, that'd be great.

Winston Frederick Bott

Yes, 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 where, very much in line with the Middle Bakken and the Three Forks 1 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 in Montana. So that's -- they're within that range and they're still holding up and sort of fitting that trend.

So I'll just make one point, though. In an effort to keep our call around 1 hour and in respect to all the other companies who're reporting today, we'll take 2 more questions.

Operator

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

Paul Grigel - Macquarie Research

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're taking a look at that right now and remodeling these efficiencies that we've seen into our 5-year plan. So it may be, exactly as Rick Muncrief sort of alluded to there earlier, that we will need fewer rigs over the entire development to achieve what we want to do in terms of production.

Paul Grigel - Macquarie Research

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 Grigel - Macquarie Research

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 this as $36 is pretty fixed?

Harold G. Hamm

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

Paul Grigel - Macquarie Research

Okay. And then lastly, just touching on the takeaway 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'll let Jeff talk to the pipeline capacity. One thing that people may or -- I hope everybody's got an understanding of this that what rail has done up here is basically eliminate the overall capacity constraints. I mean, that's been a great thing about it, if you can ship everything you produce. So the overall capacity constraint has been relieved. Jeff, you want to talk about the pipeline?

Jeffery B. Hume

Yes, on the overall pipeline capacity, starting next fall, we'll see capacity 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 9, which will feed the Great Lakes area. That's going improve that market and, I think, probably start to swing some of the barrels to the east. And then after that, we have 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's another announcement on a 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 1.5 years or so, which market's the best, we're going to try to position our barrels in the best market. But in the endgame, you're going to see these come close, come into parity. And you're going to have good transportation to the -- all 3 coasts and the midcontinent with a combination of rail and pipe. And you're going to grow a rate to a reasonable price. They're going to have to do that or the barrels will flow because there'll be enough capacity within 2 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 in the differential -- on the differential front, yes.

Operator

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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