Continental Resources, Inc.
Q2 2014 Earnings Call Transcript

Published: 6 Aug 2014

[Operator:]

Good morning, and welcome to the Continental Resources Second Quarter 2014 Earnings Conference Call. Please note that this conference is being recorded. I would now like to turn the call over to Mr. John Kilgallon, Vice President of Investor Relations. Please proceed.

[John Kilgallon:]

Thanks, Richard, and good morning. And welcome to the Continental second quarter 2014 earnings conference call. Joining me today with prepared remarks is the company's Founder, Chairman and Chief Executive Officer, Harold Hamm; Rick Bott, our President and Chief Operating Officer; and John Hart, Senior Vice President and Chief Financial Officer. Also available during the Q&A session will be various members of the senior management team

[Harold G. Hamm:]

Thank you, John, and good morning, everyone. We appreciate you joining us on our call. The Continental team delivered a solid second quarter distinguished by several key highlights. We maintained strong production through the late winter and spring months, accelerated in June with the benefit of good operating conditions. Now with the ideal summer working weather, we're continuing to drive our production growth at strong rate. Sequentially, in the second quarter, we increased production by roughly 15,500 Boe per day compared to the first quarter, a 10% increase. This absolute increase, 15,500 Boe per day in the second quarter, is almost double the sequential increase in production that we achieved during the fourth quarter of 2013 to the first quarter of 2014. Our strongest growth in the quarter was in SCOOP, where we are increasingly drawing extended laterals, which has a significant impact on well economics. Next highlight, in the second quarter, we made great progress with our Bakken enhanced completions testing program. Initial production results have been very encouraging. At our September 18 Investor Day in Oklahoma City, we plan to provide detailed summaries of our enhanced completion results in various parts of the Bakken and have these results reshape our future plans. The third highlight of the quarter was the successful first 660-foot Bakken density test, the Wahpeton project in McKenzie County. As we noted in the press release, the 12 new wells averaged more than 1,000 Boe per day in their initial testing period. We expect to have results on our remaining 3 660-foot density test by year end. In SCOOP, we've initiated our first density drilling test at the Poteet unit in Stephens County with 5 wells in the upper Woodford and 5 wells in the lower. We should have results from this test in late 2014. Our production growth is obviously impressive, and our downspacing and enhanced completions will catch the headlines but equally important is how Gary and the operation teams are continually reducing costs, analyzing and more aggressively deploying artificial lift to enhance production and overall focusing on managing a complex, fast-growing operation to maximize capital efficiency. Rig efficiency continues to improve. Our Bakken team has upgraded the fleet and on each -- on an average, each rig is now drilling 14 wells per year compared with 11 at the end of 2012. I'll have Rick give you the details on our operating results and John will cover the key financial points. I just want to emphasize that we are solidly on track to achieve our 2014 goal of 26% to 32% production growth and our 5-year commitment to triple production and prove reserves by year end 2017. Looking to the remainder of 2014, we expect continued strong production growth, particularly in the fourth quarter. Given the timing of our large pad projects, most were -- growth acceleration will be later in the year. Before closing, I'd like to highlight a couple of significant milestones in the Bakken and specifically, North Dakota. North Dakota oil production surpassed the 1 million barrel per day milestone in second quarter 2014, and the Bakken has now produced its 1 billionth barrel of oil. We are obviously proud of Continental's contribution to these records and the jobs and other economic benefits that resulted from the development of the Bakken petroleum system. We're proud to be helping move our country toward greater energy, security and independence. According to one expert, the Bakken is 1 of the 3 American oil fields to have recently surpassed 1 million barrels a day of production, and there are only 7 others in the world that have achieved this milestone. The American Energy Renaissance is literally changing the world's energy industry landscape. I've been intentionally brief with my remarks today because we're anticipating giving you a comprehensive overview of operations and strategic growth opportunities at our 2014 Investor and Analyst Day. Looking ahead to Investor Day, let me leave you with 3 strategic things on which we will focus

[Winston Frederick Bott:]

Thanks, Harold. I'd like to echo some of Harold's comments and give you additional color on our emerging opportunities. We've mentioned that Continental is on track to achieve its 5-year goal of tripling production and proved reserves. As we laid out these goals in late 2012, we pointed out our strategic objectives in the Bakken and the SCOOP. In the Bakken, we said we would focus on expanding the limits and exploring the deeper potentials of the Three Forks; that we would execute a series of density tests; we would continue to reduce well cost and focus on expanding our access to key markets on the West, East and Gulf Coast. This past year, we added a focus of enhanced completions to accelerate production and further improve the capital efficiency, as Harold outlined. In introducing SCOOP 2 years ago, we said the first priorities were to explore and delineate the play; to increase further our leasehold footprint; and then to focus on extended laterals and density drilling to understand the true potential of the play long term and accelerate our understanding, as Harold mentioned. These strategic objectives however, had to be met without us sacrificing the production and earnings growth of the 5-year plan. In the second quarter 2014, we significantly advanced our strategic efforts in all of these areas and we accelerated production growth, hitting our stride in the second quarter, averaging approximately 168,000 barrels equivalent per day in the second quarter 2014. June production averaged approximately 177,000 barrels equivalent per day. We expect moderate production growth from the level -- from this level through the remainder of the third quarter, given the timing of large pad projects, followed by strong growth in the fourth quarter. Sequential production growth was driven by strong results in both the Bakken and SCOOP. In the Bakken, we increased production 11% from the first quarter to the second. And for the first time, we broke through the 100,000 barrels equivalent per day barrier for an entire quarter. Our net Bakken production was approximately 109,000 barrels equivalent per day for the second quarter. In June, Bakken production was approximately 116,000 barrels equivalent per day, contributing almost 2/3 of the total company production. In SCOOP, production increased in the second quarter by 17% sequentially from the first quarter and almost 2x over production for the second quarter of 2013. This achievement reflects our shift to extended lateral wells in excess -- success of the exploration program as we delineate the play to the South. I would also remind you that our SCOOP wells have a slower average decline rate than the Bakken wells, which facilitate our growth momentum, particularly in the Oil window. Related to higher production in both areas, of course, is the issue of growing transportation and oil and marketing needs. Timely access to trains continues to be a challenge in North Dakota given increased demand from multiple industry sectors. New pipeline capacity is being commissioned in the second half, with additional capacity anticipated in 2015 and 2016. Midstream companies are also adding gas gathering systems and processing capacity as quickly as possible, assisted by more favorable weather the past several months. Expanded processing capacity is the critical factor as the industry works to capture value. This is another key area in which Continental is leading by example. The key factor is simply time as midstream investment catches up with the unprecedented growth in the play. The Bakken is truly a world-class oil and gas play, and its growth momentum has exceeded everyone's expectations. In terms of getting more produced gases to the market, we support proactive steps by North Dakota Governor Dalrymple to require operators to file a gas capture plan, prior to the issuance of drilling permits. Continental has been submitting such plans for a long time. And as a result, approximately 90% of our produced gas is routinely delivered to market. Continental is already near the Governor's long-term goal for the entire industry. Next, let's discuss our operating accomplishments in a little greater detail. You might recall that we spent the majority of '12 and '13 standardizing our drilling completion methods, which resulted in lower cost and strengthened capital efficiency. Since late 2013, we've tuned our attention to the Bakken, to improve recovery rates by modifying our standard completion design and incorporating enhanced completion technologies. And as John mentioned, we've put out a pack of slides. If you refer to Slides 5 and 6 for my next few comments, you'll see what I'm talking about, graphically. Given our vast acreage leasehold and drilling programs, we stand to benefit more than any operator from the optimization of well recoveries in the Bakken and SCOOP. Consequently, we are systematically testing various elements in the completion process. We want to be able to measure and analyze various components and see, how they impact results in different subplays across the Bakken. We've seeing significant uplift and early production in most areas compared to typical wells in each region. The application of different techniques has positively impacted earlier production and now, we're honing in on the combination of fluids in profit in each area that have the best cost-benefit characteristics. Our original 2014 plan was to use enhanced completion techniques to complete 16 net wells or approximately 20% of our completions in the Bakken, and we stated that this effort will be front-end loaded in the first half of the year. Through the first half in terms of operating wells, Continental completed 59 net or 75 gross using enhanced completion techniques, and we are monitoring production results at this time. Referring to Slide 6, we highlighted a half-dozen examples of the enhanced completions in yesterday's release. 3 sample slick water completed wells generated earlier production that was 35% higher than the production trend for our 603-barrel equivalent production model for North Dakota and 25% higher than nearby offset wells completed with our standard design. Another 3 sample wells completed with larger proppant loads generated early production 39% higher than the 603 barrels equivalent model and 30% higher than nearby offset wells completed with the standard design. The endgame is to determine the specific completion approach is most cost effective for each part of the play as we transition into full-field development. As Harold mentioned, we'll give more information on this at Investor's Day. Backing up to Slide 4, I want to highlight our Wahpeton density project in McKenzie County, and we're very pleased with the results. This was our first 660-foot density drilling test with a total of 12 new wells in the Middle Bakken and Three Forks, first, second and third benches. The average IP rate for new wells was 1,730 barrel equivalent per day in the Middle Bakken zone, 935 barrels equivalent per day in the Three Forks first bench and second, and third bench wells averaged 700,000 barrels equivalent per day. This is a solid test result especially considering that the Wahpeton wells were completed with the standard completion design. It's too soon to talk about conclusions on the Wahpeton well much beyond IPs, but we plan to conduct post-testing and we'll be watching our production results after we put these wells on our official list. The next three 660-foot test, the Lawrence, Mack and Hartman pilots, will be completed with enhanced completion designs. Our goal is to integrate the knowledge gained from our completion design test with our new downspacing pilot results to maximize recoveries, accelerate production and thus drive higher realization returns and greater MPD as we transition into full-field development. Referring to Slide 8, and talking about down-spacing opportunities in Bakken to those in the SCOOP. We've commenced drilling, our first density pilot in the neck area of the SCOOP in Stephens County. The Poteet project involves drilling 5 separate 2-well pads. We expect drilling to be completed by the end of the third quarter. In this area of play, the Woodford's approximately 380 feet thick, leading us to believe it should be developed on at least 2 levels and we're testing that concept. As our exploration program is progressed to the south of play, we found other areas where the Woodford has even greater thickness. We'll talk about this in greater detail next month but the headline is that SCOOP is a world-class, repeatable resource play who's potential, we are just beginning to unlock, as Harold mentioned. You've seen the impressive production growth over the past 2 years and we're just getting started. We're in the very early days of understanding the geological potential of the SCOOP petroleum system, just beginning to realize drilling and completion efficiencies and just beginning to unpack the tremendous value creation opportunity that we have in SCOOP. We pride ourselves at Continental in terms of innovative exploration thinking, pushing the technical envelope and execution in the field to create value for our shareholders. Results from our density pilots and enhanced completion programs illustrate the power of this strategic approach. We think this combination of efforts provides us a unique opportunity to maximize recoveries, enhance returns, enhance capital efficiency and maximize that NPV of the premier assets that we have assembled in the Bakken and SCOOP. It's already in the game but Continental is an early-stage growth company. As Harold said, exploration of these resource plays can take many forms but all hinges on the drill bit. We look forward to giving you an update in September. With that, I'll turn it over to John Hart.

[John D. Hart:]

Thank you, Rick. The second quarter of 2014 was a solid performance with record EBITDAX totaling $868 million. Our cash margins remained strong as well at $55.45 per barrel and 75 percentage -- 75% on a percentage basis. As mentioned earlier, our production trend has gained momentum since the first quarter, setting the stage for the back half of the year. We're very focused on ensuring we are capturing the highest price possible in our oil and natural gas marketing efforts. As other peers have already announced, we did see weakness in NGO process in the second quarter, especially compared to the first quarter with a heavier-than-usual winter demand on the heating-centric NGLs. This weakness had a larger impact than usual on our financials. All differentials were higher as well, but this was on a higher absolute commodity price, so above our internal forecast for net realizations. These trends may continue through the remainder of the year. Last quarter, we mentioned, we anticipated a large amount of new infrastructure line fill to begin in the second quarter. It turned out that this was not the case due to delays from the midstream operator. Instead, in the second quarter, we sold roughly 78,000 more barrels of oil than we actually produced. We expect oil inventories to increase in the second half of 2014, as line fill requirements are satisfied for new pipeline infrastructure being developed in key operating areas. This may result in reduced sales volumes in the second half by an aggregate of approximately 500,000 net barrels. Although the impact may be partially offset by sales of stored production. In the quarterly results, our LOE, production tax and G&A were within previously disclosed annual guidance and improved in many ways. DD&A increased in the quarter for several reasons

[Operator:]

[Operator Instructions] Our first question online comes from Doug Leggate from Bank of America.

[Douglas George Blyth Leggate:]

I'm guessing we're going to get a lot of details in September, but I'll try a couple, if I may. Rick, you talked about the 59 wells that you used the enhanced completions, I guess, in the first half of the year, but you only called out couple of the well results in the presentation. I'm just wondering if you can give us some kind of more of an average for the wells that have got enough production history. And just related to that, in the past, you've kind of talked about whether you were accelerating production or actually improving recovery, I'm just curious if you'd draw any conclusions from the tests that you've seen yet? I've got a follow-up please.

[Winston Frederick Bott:]

Sure. Well, on the wells that we've got, what we gave you is just a selected group from the, 2 of the completion designs that we've seen wells more -- that we've been very, very pleased with the results, a lot of the other, 59 wells that we've done are just really don't have enough production, therefore, is yet to be comfortable in giving an average. Continental likes to have a little bit of production under our belt before we confidently come out and say what that uplift will be. But I think Gary can, the range is quite broad but most the results are quite exciting. So let me let Gary to give some color on the range of outcomes we've seen on completion design.

[Gary E. Gould:]

Sure. A little bit of comment on that. We are tracking all our various tests. And as we look at the data, most of the wells to date just have about 30 days of production back, so it's very early. The range we're seeing on slick water as well as larger profit amounts is between 0 -- or I should say, positive 2% to over 100% based on all the wells we've looked at to date on this particular technique. So we're especially encouraged by putting more proppant into our completions as well as testing slick water.

[Douglas George Blyth Leggate:]

Is there a regional variability behind that, Gary? It's quite a wide range.

[Gary E. Gould:]

Well, it is a wide range. A lot of that has to do with the number of wells we've tested so far. It's -- oil and gas is very statistical in nature and so the more wells we test, the more we're going to be able to hone in on.

[Douglas George Blyth Leggate:]

So and then the recovery rate? Sorry, go ahead.

[Winston Frederick Bott:]

So what’s your question about recovery?

[Douglas George Blyth Leggate:]

Yes. Sorry, my question on the recovery was, I think in the past, you said you haven't quite figured out if the additional cost was going to be -- how the economics are going to play out, determining whether this was an actually increasing recovery or if it was accelerating the production of the same amount of resource if you see, what I mean. So it may be little early to figure think about. I was just curious, hope you had get some thoughts that you could share with us.

[Gary E. Gould:]

Yes, it's very early. I think that takes a long period of time to see as we measure declines to figure out how much of this incremental production is truly incremental reserves versus how much is accelerated. The second thing is, it's very important as we evaluate these to look at spacing at the same time that we're looking at completion analysis. And so we're already are combining our looks on that to understand how do we maximize the profitability with that combination. And so these are things that we continually evaluate. We have multi-disciplined teams working on this. I mean a combination of geologists, operations engineers and resource development engineers and as -- has been mentioned earlier, we're going to be presenting a lot more of that information, a lot more detailed data here in September in about 6 weeks.

[Winston Frederick Bott:]

Doug, if I can pick up on one more, just -- I'm going to add one point to Gary's comments then. It was perhaps, commented by John in his comments. As that rolls into our financials, we've essentially taken a conservative approach for our reserve bookings and all those wells and so that conservative approach is the way we translate into our financials. We are optimistic, however, and it's kind of consistently, if we took an average, we're seeing that 25% to 35% uplift. Basing this on Harold's 50 years’ experience, he made the comment that rarely in these plays have we seen an uplift that's that significant in the near term that doesn't at some ultimately point, translate into reserves and into recovery. So we're very optimistic. We're currently evaluating all the results that we have doing some testing, evaluating those a little bit more production history, and we'll try to give you a lot more guidance on the recovery factor and reserve impact and uplift for the whole play -- for the play as a whole, when you come in September.

[Operator:]

Our next question online comes from the line of Pearce Hammond from Simmons & Company.

[Pearce W. Hammond:]

First question was has any of your results from pilots changed your view on the first bench of the Three Forks EURs or should we still assume a 603 mBoe EUR?

[Gary E. Gould:]

I think the reserves are going to vary throughout the play. And so what we're doing is we are evaluating -- with another multi-disciplined team that we have made up of geologists and resource development engineers, we're evaluating the original oil in place, the reserves performance throughout multiple geodomain areas to understand what type of type curves we have throughout the play. So there's variability throughout the play because geology varies throughout the play, and that's why our tests are being performed throughout the play also. So there'll be more information to come and more details in September, but we are evaluating that variation.

[Winston Frederick Bott:]

So Pearce there, we're optimistic there. When we get to the September, we will be able to sort of break this down by zones and give you guys some of that guidance on whether or not we think, the facts should improve. That's one of our targets that we're working towards.

[Pearce W. Hammond:]

And then my follow-up, and I know you're going to address this next month at the Analyst Day in Oklahoma City, but if there's any help that you can provide us, just maybe even some guardrails around what '15 CapEx and production guidance might look like, or what are some different ways we can think about it from our perspective?

[Winston Frederick Bott:]

Yes, we will. We certainly intend. I think we came out ahead of -- most of the players last year to let you know what the 2014 will be, and that's one of the plans that kind of Harold outlined there that we will give you a look on how has all of this thing that we're doing going to translate into the near term, the 2015 budget and then it how is it going to impact our 5-year plan and then what does it look like for the whole play and what does that mean for Continental beyond that, beyond 5 years. So we've got a lot of moving parts. There's a lot of things that are -- that we’re working on and we are hopeful that this will be, as Harold says, an information rich event for you. So please do come.

[Operator:]

Our next question online comes from Leo Mariani from RBC.

[Leo P. Mariani:]

Guys, just in terms of the enhanced completion practices, it sounds like you guys did your roughly, your budget of wells here in the first half. Sounds like you're encouraged. Should we still be expecting to see more wells in the Bakken with enhanced completion techniques in the second half of the year here?

[Winston Frederick Bott:]

Well, that's exactly right. As we mentioned in the statements there, the Lawrence, Mack and Hartman, those will have some new completion designs in there and then, we're kind of evaluating on what the program is going to be going forward. So we'll give you guidance on that, again, in 6 weeks’ time. But the teams are working on that.

[Harold G. Hamm:]

Leo -- we're moving about as fast as the equipment will allow us up there in the play and there've been some equipment limitation for these bigger jobs, high-volume jobs. So we're moving as fast we can.

[Leo P. Mariani:]

Okay. That's good to hear, for sure. I guess, just looking at the Bakken, I think you guys talked about completing 159 wells in the first half of the year. You've got 287 scheduled for the full year. I guess it implies a modest slowdown in the second half. You guys talked about out [ph] production accelerating more in the fourth quarter than the third quarter. I guess can you maybe just talk a little bit to completion, sort of cadence here in 3Q versus 4Q. And are you going to see something similar in the SCOOP as well? Is that also more kind of fourth quarter loaded?

[Gary E. Gould:]

Yes, and that's basically driven by the timing of pad. So you should be encouraged by the production growth that we've already seen. We've already mentioned what our June number was. So currently, we have production approach at 180,000 BOEs per day. So that's already strong growth over our average for the second quarter. But it was up -- as was also mentioned earlier, we expect a little bit of flattening due to the timing of all our pad developments through the third quarter and then accelerating again in the fourth quarter. And so we're well on our path to meeting our production guidance and expect future growth to continue into next year and look forward to showing you that next month.

[Operator:]

Our next question online comes from Mr. Brian Singer from Goldman Sachs.

[Brian Singer:]

I wanted to follow-up on the Wahpeton pad. One can certainly look at the middle Bakken rates, that seem positive and the 9 wells elsewhere, perhaps less so. This seems very early on, but can you provide a little bit more clarity on how and what you're seeing at Wahpeton compares to what you expected and what you were seeing at some of the other pads, less about the middle Bakken and then more color with regards to the Three Forks zones?

[Gary E. Gould:]

Well, especially for the Wahpeton, that one is very early for us. And so what we have is we have wells sort of flowing back. They're not all on artificial lift yet, so there's a lot of optimization yet to prove on. And so what we see is very strong initial results that we're pleased with and we expect that, that will continue to improve over time as we put wells on artificial lift and pump them down.

[Jack H. Stark:]

Yes, and Brian, this is Jack. I just might add that these initial rates are fairly similar to what we experienced in the Charlotte unit just to the east of here. And so my feel here is that really things look like they're right in line of what we experienced there. And what I'm really encouraged about here and a lot of times people lose sight of this, when we see these varying different IP rates coming from these different layers, different benches. To me, what that's indicating is that we're tying into reservoir rock that hadn't previously been tied into. We're getting some unique reserves because these different wellbores are performing differently. So I think they're reflecting the rock that they're in. And I think it just adds to the -- I guess the, the thesis that we have here is that there's oil in place in these lower benches for us to harvest.

[Brian Singer:]

Great. And then my follow-up is with regards to the rail bottlenecks that I think Harold mentioned in his opening comments. Is this a heightened potential constraint here to Bakken growth in the second half? And can you just talk about how you see transportation costs evolving over time here? And then how much is related -- how much of all this is related to regulatory changes/clarity versus economy driven, just competition to use the rails from other industries.

[Harold G. Hamm:]

Well, what we're seeing -- what we're looking forward to in the second half of the year is additional pipeline capacity coming on, and which will take a lot of the heat off the rail. And so we're seeing the rail movements improve continually. We've seen that through the summer here but occasionally, you have a slowdown in that. But I think the addition of other pipelines coming on is going to help that whole situation. So you take a couple of hundred thousand barrels off of the -- and put it on pipe, it helps a lot.

[Winston Frederick Bott:]

Building on that, Brian just, we talked about this last quarter, I don't know if you picked up on it, but we kind of anticipated the, if you will, the inconsistency. And so we built infield storage so that we're able to manage this. When we talked about filling that last quarter. We continue to do that and so we continue to stay ahead of this game to make sure that we're able to get our production and be able to optimize and manage the logistics. But the crude logistics has clearly, always been an issue for the Bakken and we continue to work those issues both at the field level and getting into the -- maximizing the different market we can get it to.

[Operator:]

Our next question comes from Subash Chandra from Jefferies.

[Subash Chandra:]

First question is the SCOOP well results that you divulged. How did that compare to expectations. And the lateral length of those, I believe, Grady County wells, are those in line with what you intend to do down there and were there some quarter low results as well during the quarter?

[Gary E. Gould:]

As far as initial results, we're very pleased with how the wells are coming in on the SCOOP. And when we look at our wells, we've got some oily wells that are declining at a much flatter rate than what we would have expected if we looked at some of the gassier regions down there. And so we're very pleased with the overall economics.

[Harold G. Hamm:]

In the -- to the lateral lengths, we continually moved up more and more, the wells been drilled have been long laterals. And we're able to do this successfully, across much of the play down there, so we're very pleased with what our team has done in that regard.

[Subash Chandra:]

Right. So the Colt and the Mackie being in that 4,000 -- right around 4,000 feet, was that because of lease consideration? Is that just sort of a -- an initial view of the County with intentions to increase that lateral length meaningfully?

[Jack H. Stark:]

Yes, Subash, this is Jack. They were limited both by lease and also geology in those areas. And I might mention too, in the Mackie well, we've got 4,200-foot of lateral there but about 3,000 of that was actually in the Woodford. So that the area is a little more structural complexity and, so we didn't have those 4,200 in zone.

[Subash Chandra:]

Okay. And as a follow-up for Harold, can you help me interpret I guess the studies that you guys had sponsored, as well as others? And I guess the final study talking about again, the oil being very, very similar but raising the packaging risk on it, risk number or however they measure it, but then still saying that it could be transported on more 111 cars. Could you just sort of talk about your current view now that the study has been done, and if there's anything else in the works to debate your point?

[Harold G. Hamm:]

Well, we -- these are very light -- call it a high-quality oil up there and that's why refineries like it so well. And the study has basically shown that similar oils, I mean this falls in the category, and we've been -- it's been labeled properly and now, people want to compare it to other oils but they didn't do the study on the other oils. So like a Permian and West Texas intermediate for instance. So that will be done but the volatility range is much the same as other oil, similar gravity oil, so that's been done. We feel good where we're at with the -- as far as the new regulations, we feel like we need proper time to upgrade cars and as -- but we're not seeing anything come out of that. That's -- you know rail was quick to respond to, all safety measures

[Subash Chandra:]

Okay. If I can just finish with asking to elaborate on the rail bottlenecks

[Winston Frederick Bott:]

I can touch that, Subash. No, they weren't associated with these regulations at all. They were more weather related and just demand from all the different industry sectors and there's more about trains in the field not showing up. And so essentially, the rail industry has responded by looping tracks, building more tracks, building more cars, loading facilities are getting a lot more efficient. So long term, we don't see this as a problem. Is just you've got to -- sometimes you got to cycle through as everybody hits production at the same time. Can I pick up, Subash, on one of your questions? I just want to come back to those Colt and Mackie wells that -- your point there about one thing that just to realize is, we explore this oil window, those wells, we don't -- again like, we don't necessarily, like the Bakken, we don't necessarily go out there for a huge IP rate. These are very, very good wells and the nice thing about this oil window, and we might define the oil window slightly different than some other operators. But our true oil window is true oil window [ph] Bakken well. And the declining curve on these wells are really very, very low. And so and that's why you're able to see the production adds with not a whole lot of new wells. And so this production growth is because we have very flat decline in these oil window wells. So we're very excited about those counties that you mentioned there as well.

[Operator:]

Our next question online comes from Brian Corales from Howard Weil.

[Brian M. Corales:]

Two questions. One on the SCOOP. Have you all drilled or put the lateral in the upper portion of the Woodford? And if so, I mean, did you have similar results as the lower Woodford?

[Harold G. Hamm:]

Yes, Brian, we have tested both the upper and lower halfs of various wells throughout the play, and we do see similar results. We're looking at just now as with our test here to try to determine where we're in areas that are over 200-feet thick or so. We're thinking we're probably going to need to have wells in the upper half and lower half.

[Brian M. Corales:]

Got you. Okay. And then with all these down-space tests, I guess the next step is when does this go to kind of full-field development or at least in that area, where -- when do you think you're going to see another Antelope-like development? Is that something that's beyond 2015, or is that kind of what we're all setting up for at the Analyst Day?

[Winston Frederick Bott:]

Well, I think it'll be a balance. We'll have to look at -- we'll probably do just like we did in the Bakken, where you have to balance the HBP requirements, the rigs that are available and moving into full-field development. But I think you'll see us come out with more larger drilling programs in a concentrated area because we feel like we've de-risked the play significantly. We'll probably be in and around that neck area to start because we have the most data there. But I think you'll see a combination of both, and we're in the process of debating that internally as we put together our long-term plans.

[Harold G. Hamm:]

And to follow-up on that, Brian, we certainly will be talking about this in Analyst Day.

[Operator:]

Our next question online comes from Drew Venker from Morgan Stanley.

[Andrew Venker:]

I guess you guys noted some very big rates in the gas condensate window in SCOOP. Curious if those were above your expectations and if maybe that won't change how much cap rate you directed to that window of the play?

[Harold G. Hamm:]

I think to your -- quick answer is, yes, they were very good rates and met our expectations at least and some were better than that. And of course, the better the wells you drill, the more money you're going to put there, so yes to both those.

[Andrew Venker:]

And then Harold, as a follow-up. Can you speak to how much of your activity is directed to the oil window and the condensate window this year?

[Winston Frederick Bott:]

50-50.

[Harold G. Hamm:]

50-50.

[Operator:]

Our next question online comes from Joe Allman from JPMorgan.

[Joseph D. Allman:]

In terms of the new completion designs, if you found the economics have improved, what would prevent you from adopting the new techniques right away and drill just better economic wells instead of just really good economic wells?

[Gary E. Gould:]

Nothing would prevent us from doing that, so that's why we're continuing to experiment with the new completions. And from what we're learning in the Bakken, we're also applying that quicker down south in the SCOOP plays as well. And so we're very focused on maximizing the profitability.

[Joseph D. Allman:]

Got you. So are you saying that you're already going beyond the 60-or-so wells and you're like immediately adopting them and say, instead of just using that technique on those additional pilot wells, you are actually more widely using the new completion techniques? So that's one. And then back to the Wahpeton, could you just talk about the -- how those downspaced wells compared to nearby less densely drilled wells? And have you seen any communication and any -- do you expect any EUR degradation there?

[Winston Frederick Bott:]

Sure. Joe, I think the way we'd answer that is as we mentioned in the initial description there, we do have more completions planned. We talked about the Lawrence, Mack and Hartman, those pilots. We've got some other things, we're working up some plans. Gary talked about, trying to get an understanding by the different areas of the different subplays in the basin. So we are building all those plans, and I think that's one of the things that we're saying. To put that in context, it's best done at an Analyst Day where we can show you the data, and we can talk about that. So that's where we'll be doing that. With respect to Wahpeton, I don't know at the top of my head what nearby wells are but those are in line or better. Haven't seen any interference or anything like that. So no, we will -- but these are only IP rates. So we haven't done post-testing, which is probably the best way to answer your question and we will be doing that in the near term, and hopefully, getting an answer on that. But we are -- we're pretty optimistic that this downspacing continues to give us results that are encouraging, as well as surprising. And so it helps us hone our ideas. And if you think back about our outcomes from that very, very large microseismic program we did where we basically saw on the subsurface that we were not stimulating and touching as much of the rock that previous models had thought. And so all of our efforts here both in downspacing as well as the larger and larger completion designs are really trying to get at that question and trying to get what is optimal? And of course that all translates into capital efficiency but we will try to make sure we're getting the most oil out of this rock as we possibly can in a cost-effective and timely manner because, of course, oil is worth a whole lot more to the investors if we can produce it today and next year, then years down the road. So we're trying to bring as much acceleration story to that as possible.

[Operator:]

Our next question online comes from Mr. Jason Wangler from Wunderlich Securities.

[Jason A. Wangler:]

Just had one quick one in the SCOOP. Moving more and more towards the extended laterals. Is there any constraint besides permitting there or acreage, or is it maybe more just as you get more HBP done, you'll kind of start moving toward that given the economic benefits?

[Winston Frederick Bott:]

Well, I think I'll let Jack comment on it. But as you move down to the South, this is a tectonically much more complex, structurally much more lateral changes because of the -- because you're in a big fold belt there. And so those are -- it's probably more a geologic constraint. All the leasing in the spacing units is essentially, you can do that to an administrative process. So it's more about the geology and trying to make sure you tie and get the right length of well in the right area. So 3 seismic is important here but our program is running, and we're understanding this as we move further to south. So but the good thing about that is it provides really an enhanced fracturing and a whole lot better well. So there's operational constraints but I think we're figuring those out as we move.

[Harold G. Hamm:]

And I would say, Jason, that about 50% of our wells, right now, are drilling cross lateral -- across unit wells and I can see that easily get into 75%. So we will be able to play it, broadly across the play.

[Operator:]

Our next question online comes from Marshall Carver from Heikkinen Energy.

[Marshall H. Carver:]

On the SCOOP acreage, how much of your SCOOP acreage is picking up so that it can potentially accommodate wells in both zones like your downspacing pilots going to be? How much is in that 380-foot thickness range?

[Harold G. Hamm:]

Yes, we're kind of right now are using 200-foot as a cutoff in our minds right now, and we'll see how that falls. But right now, that would represent about 40% to probably 50% of our acreage.

[Marshall H. Carver:]

Okay. On the -- any comments on go-forward expense guidance? Should the DD&A track the 2Q level going forward? And any comments on 3Q and 4Q on other expense lines?

[John D. Hart:]

On DD&A, if you look at the annual guidance, we're clearly above that year-to-date. For the full year, I think we'll probably end up being a bit above that top-end guidance. It's early on, a lot of these wells were very optimistic with what we're seeing in the early time production results. So we hope to see some improvement there as we go forward. The back half of the year, we're focusing -- part of the component we talked about was the exploration area, testing some of the extent of our positions in different areas. Our drilling in the back half of the year is more focused in areas that we know that are strong, and we should see improvement from that. So we're optimistic about that. Before 2014, I would expect we'll be above the top end. That's something that we'll look at -- we're looking at very closely. We'll give you some updated guidance at Investor Day. I think it's important for you to also note that on DD&A being a little bit above, you're seeing the other variables, uh, lifting cost, G&A, production taxes, they're all towards the tight side of guidance or in some cases, better than the guidance. So there's a little bit of a give-and-take but just the nature of where we're at. We're very early and, but we're very excited about what we're seeing.

[Operator:]

Our next question online comes from Matt Portillo from TPH.

[Matthew Portillo:]

Just a quick follow-up on the DD&A side. I was wondering if you -- if it's possible to provide a little bit of color on how much of the increase, potentially, came from the enhanced completion cost increases about the increase in the EURs versus how much kind of came from acreage delineation or deeper zone delineation.

[Harold G. Hamm:]

I'll comment on that first and see if anybody else wants to comment. I would tell you that my valuation of it is that we -- the wells that had first production in the first half of this year were scattered in a lot of areas where we were holding acreage or testing areas around the outside, trying to make them more economic. And so I know our teams are working on multiple things to improve the economics. And so one thing is shifting rigs from HBP new acreage, that might be more on the fringes to concentrating on the highest rate of return areas. So that's going to help improve it. And then the completions themselves are helping to improve it also.

[John D. Hart:]

Yes. Go ahead. As far as the spread, I think, it's spread amongst those, across the broader basins, so it's hard to give you a set percentage. There's some variability on that. Because some of those projects can overlap in what categorization you're looking at.

[Matthew Portillo:]

Perfect. And then just back to the Anadarko Basin, I know that the SCOOP is obviously a very important part of your drilling program. Just curious with some of your acreage to the North in terms of the stack potential within the Merrimack or kind of the Cana, I was wondering if you could provide maybe an update or any thoughts around either kind of testing the Merrimack or kind of testing some of the upside fracs in the Cana as well?

[Gary E. Gould:]

Sure. Just as far as the stack is concerned, we've got 102,000 net acres in there, and we're -- really, we are just watching activity. Activity has started to pick up, up there. I mean, obviously we've had some initial wells drilled, and so we're seeing more and more activity up there. And so we're encouraged with what we're seeing up there as far as some of the early time results. And I will mention a lot of that acreage we have up there is legacy acreage, so a lot of it is HBP. So we have the luxury of being able to focus our dollars where we have higher rates of return right now, and then we can build on this as time allows.

[Operator:]

Our next question online comes from Noel Parks from Ladenburg Thalmann.

[Noel A. Parks:]

A couple of things. In the SCOOP, I want to get an update on your thinking about NGL marketing. I'm just wondering as we get close to looking into 2015 and you think about how things looked a year ago, I just wondered if the outlook has played out about like you, you guys expected for NGL processing going forward, or has the market unfolded differently than you were planning?

[John D. Hart:]

We've got -- I think there are a number of key variables there. We've got plenty of takeaway capacity. We're seeing some potential for incremental capacity going to some very good markets. We like that optionality. There's plenty of processing and more is being -- is coming in. You've seen some announcements over the last month of different plants on that. Yes, there is a little bit of seasonality with the weather last winter, certainly, benefited us with a colder winter. And we were certainly hopeful of that this year but, blended in with our overall view on the play. It's a component of the economics there. And this is an area we're very excited about, it has great economics for us and pleased with the infrastructure, and we're pleased with the incremental infrastructure that's coming.

[Noel A. Parks:]

Okay. And I guess sticking with infrastructure a little bit. Could you clarify for me what the status is right now with line fill, for example, in Pony Express, I know you quantified sort of the effect that, that line fill might have on fills volumes second half of the year. I wondered if that -- that figure, the $500,000 you gave also included any other pipelines or whether that was all Pony Express.

[Winston Frederick Bott:]

It includes some field gathering things as well. So there's a lot of things included in that number, so perhaps we're not the best to comment on that but those lines are being filled and we have a little bit of contribution to it.

[Noel A. Parks:]

Is that process about wrapped up?

[Jack H. Stark:]

No on Pony Express it isn't -- have some [indiscernible].

[Winston Frederick Bott:]

No, it will be going on for another couple of months.

[Jack H. Stark:]

Yes.

[Winston Frederick Bott:]

Just one other point, Noel, on SCOOP. You asked about -- just one point that John talked about that incremental infrastructure that's coming as well. So the strategy is essentially the same as it was in the Bakken and that is being able to have a portfolio approach in flexibility markets. So with that, we'll be able to get to both Mont Belvieu or Conway, so we're going to have pricing in either and we can take advantage of those -- both of those markets to be able to get our gas and our NGLs too.

[Operator:]

Our next question online comes from Ryan Oatman from SunTrust.

[Ryan Oatman:]

On the rules on pilot, can you describe how those results are informing your completion designs and spacing assumptions moving forward, I know there a couple of variables there. Just wanted to see if you can comment on both the completion designs and the spacing.

[Gary E. Gould:]

It's still a little bit early on that. It is something that we'll be able to comment on next month. As you know, it's a combination of both 1320 spacing but we also have done multiple different types of completion analyses, and we're just continuing to evaluate that, and we'll be able to report out those details next month for you.

[Ryan Oatman:]

Okay. That's very good. And then I don't want to beat the Wahpeton question to death. But can you describe just maybe the variance between the benches of the Three Forks 1, 2, 3? Are those wells producing similarly, or do you see variances between the benches?

[Gary E. Gould:]

It's hard to comment on right now because it's very early. So what happens, especially early in the first 30 to 60 days, you're talking about several wells that are still flowing back on their own and so they are very strong production. At the same time, we don't have them on artificial lift and so you just don't have a consistent trend in which you can evaluate the reserve potential. And so that will be one more thing we'll try to comment more on next month.

[Ryan Oatman:]

Okay, fair enough. And one final one for me. On the SCOOP wells, is the condensate produced at the wellhead, or is it recovered later at a processing facility?

[Gary E. Gould:]

No, it's recovered at the wellhead.

[Ryan Oatman:]

Okay. And is it run through stabilizes at that point?

[Winston Frederick Bott:]

Not currently.

[Ryan Oatman:]

Not currently. Are there any plans to increase sort of the use of distillation towers given that the recent rulings from the Commerce Department?

[Winston Frederick Bott:]

Ryan, let's just say, it's a hot topic of investigation.

[Operator:]

Our next question comes from Paul Grigel from Macquarie.

[Paul Grigel:]

Just following up on Ryan's question there. Has there been any update on your crude export application or any ongoing discussions post the recent decision?

[Winston Frederick Bott:]

No.

[Paul Grigel:]

Okay. And then second, on the SCOOP, you guys added 35,000 acres during the quarter. What's the longer-term opportunity for continuing to add acreage in the play?

[Harold G. Hamm:]

There's always opportunities out there. We're aggressively pursuing key mineral leasing and acquisitions. We had 13 acquisitions this quarter. We'll continue to pursue every opportunity that we can. We've got a task force put together and couple of hundred brokers out there. We're going to continue.

[Operator:]

And our final question comes from Gil Yang from DISCERN.

[Gilbert K. Yang:]

With the greater expense for the enhanced completions, how should we view your capital budget for the year as it's trending based on the sort of the number of wells you have completed and likely to complete using those enhanced completions?

[John D. Hart:]

If you look at the -- if you look at us at midyear, we're right on top of the midyear capital budget, I think we're, maybe 4% or 5% ahead. So we're not at all that far ahead. We have a lot of optionality in the rigs and how we deploy those in the different areas. And it's just the timing of completions. So there are a lot of variables that go into that. That's something that in conjunction with our 2015 budget, the exit out of this year and entrance into next year, along with the longer-term look towards our updating of the 5-year plan, that's something that we're actively looking at. We'll give a lot more detail and color on that at Investor Day.

[Gilbert K. Yang:]

Okay, great. And then my last question is just the question of -- the hand completions, I think you've mentioned were more targeted towards the more frontier areas, and you're going to pull back to maybe drilling more of the more known areas. Have you seen, based on the results you've seen so far, have you seen a difference in the performance of those enhanced completions in the more proven areas versus frontier areas? And I apologize if that was answered already.

[Harold G. Hamm:]

I can comment on that. First of all, the completion analysis we're doing, the testings we're doing is spread out through all our areas. And what I was trying to emphasize was our drilling locations were making the shift from HBP in the edges towards developing our areas of more pad drilling in our best areas first. So that's what differentiates those 2.

[John Kilgallon:]

Thank you, everyone for joining our call this morning. If you have additional follow-up, certainly myself and Warren will be available. That concludes our call. Thank you.

[Operator:]

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.