Continental Resources, Inc.
Q2 2013 Earnings Call Transcript

Published: 8 Aug 2013

[Operator:]

Good morning, and welcome to the Continental Resources Second Quarter 2013 Earnings Conference Call. I would now like to turn the call over to John Kilgallon.

[John Kilgallon:]

Thanks, Lacey, and good morning and welcome to the Continental Resources Second Quarter 2013 Earnings Conference Call. This is John Kilgallon, Director of Investor Relations. Joining me on the call this morning with prepared remarks are Harold Hamm, Founder, Chairman and Chief Operating officer; Rick Bott, President and Chief Operating Officer; Rick Muncrief, Senior Vice President of Operations; John Hart, Senior Vice President and Chief Operating Officer. And also available during the Q&A session will be Jack Stark, Senior Vice President of Exploration; and Warren Henry, Vice President of Investor Relations. A few housekeeping items that we'll cover before going into the forward-looking statement. In conjunction with the earnings and our call this morning, we have posted a summary presentation as a reference tool. This presentation can be found on our website, in the For Investors section, under Presentations. The slides are also included in the webcast portal for your viewing during the call. If you have not printed yet, I recommend you do so now. You may have also noticed we've added a few quick links to the homepage in the upper left-hand corner to make all the earnings data easier to find. 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 a reconciliation of adjusted net income per diluted share to GAAP net income per diluted share, please refer to the section of Non-GAAP financial measures in the second quarter earnings release at the conclusion, which is posted on our website at www.clr.com. With that, I'll turn the call over to Harold. Harold?

[Harold G. Hamm:]

Good morning. Thank you for joining us today. We are pleased to report strong performance for our second quarter ended June 30 including record production and cash flow. The key, of course, was excellent production growth. Second quarter production averaged 135,700 Boepd, up 43% from the second quarter of 2012. This production growth and additional operating efficiencies resulted in record EBITDAX of $708 million, up 14% from the first quarter of 2013 and 68% higher than the second quarter of 2012. You could refer to the first slide of our presentation. I won't go through each bullet point and be brief here. And then also on the second slide, aside from increased production, the other benefit of our industry-leading drilling program is increased proved reserves. Our mid-year estimate of 922 million barrels of oil equivalent in proved reserves represents a 17% increase over year-end 2012 proved reserves of 785 million Boe. Consistent with our value creation model and focus on crude oil, these major reserves are 87% operated and 70% oil. In fact, our estimate of proved reserves has more than doubled in the past 24 months. Finally, the Continental team is executing our growth program while improving capital efficiencies and staying within our 2013 capital budget. At June 30, we spent half of our non-acquisition CapEx budget for the year. So first, I give the team very high marks for their performance in the first half. They are executing at a very high level. Second, Continental is poised for strong performance in the second half of 2013 and extending into 2014 with the opportunity to create even greater shareholder value. We plan to maintain excellent performance completing 2013 as a great first year in a 5-year growth plan. Last October, you may remember, we shared with you this new 5-year plan focused on building shareholder value by once again tripling production and proved reserves. Key objectives for that are

[Winston Frederick Bott:]

Thanks, Harold. I've got 2 objectives. I want to expand on our operating results a bit, and then update you on several of our key catalysts for the remainder of the year and early 2014. First, we've set a consistent pace through the first and second quarters of the year with 42% higher production growth compared to the first half of 2012. We're currently as of today maintaining our strong momentum with current production slightly in excess of 140,000 barrels of oil equivalent per day. Our third quarter production growth rate, however, is slowing slightly as planned, as we and other operators shift to pad drilling and larger pads in the Bakken. The net effect should be to boost production significantly in the fourth quarter and early 2014 compared with the third quarter of 2013. In summary, our 2013 production flow of 35% to 40% growth year-over-year can be tightened and moved upward. We're probably headed for the upper end of the target range, and will likely generate 38% to 40% production growth this year compared to last year. Note, as Harold mentioned, this is with no increase in CapEx. Next, we have spoken frequently in the past year about strategic importance of Continental's portfolio strategy in oil and gas marketing, especially the development of strong coastal markets for Bakken crude oil. As the production leader in the Bakken, we also led the way by increasing the use of rail and pipeline alternatives throughout North America, but especially in the U.S. Our strategy has passed the test. We continue to balance medium-term commitments with the ability to sell to spot prices. We continue to implement this portfolio approach to balance rail and pipe transport from the Williston. In August, rail is expected to account for approximately 75% of Bakken shipments. We continue to cultivate new rail customers on the East, West and Gulf Coast to capture the best price as their appetite increases for the premium Bakken barrel. Finally, volatility will likely be an ongoing factor in the oil markets and we will adapt to it. Now let's look at key catalysts on the horizon primarily related to our Bakken exploration program and further delineation and new opportunities in SCOOP. So let me start with the Bakken. You may want to refer to Slide 5 in the slide deck as we discuss the Lower Three Forks exploration program. We're on target to have all of this year's 20 wells completed by year-end, bringing the total program to 22 wells. To recap, our Lower Three Forks exploration program was designed to

[Richard E. Muncrief:]

Thanks, Rick. As you no doubt recognize from our earnings report, the Bakken, SCOOP, Red River units and new venture teams are performing very well, continuing to reduce well costs, strengthen our capital efficiency, manage our base assets and identify new opportunities. The operating group is executing our growth plan at an exceptionally high level. But in addition to production growth and lower well costs, the Continental team is steadily improving our safety performance. Continental's safety program encompasses not only our own employees in the office and the field, but also the people who work for us as contractors in drilling, well completion, production and other key activities. We also remain an industry leader in the Bakken with regard to reduced flaring, consistently experience a rate that is 1/3 of the industry average in North Dakota. Now let's talk about improved operated well cost. Last October, if you recall, we set a goal of achieving an $8.2 million completed well cost by year-end 2013. This compares to our 2012 average of $9.2 million completed well cost for a single Continental-operated well, and compares favorably with the $11.3 million per well that we experienced from outside-operated wells. We have now hit our $8.2 million target 6 months early. And we anticipate consistently delivering operated wells for $8 million or less. Thus, this is our revised target for year-end 2013. I'd also like to note that our completed operated well costs include oil drilling, completion, facilities and artificial lift. Some operators in the play don't include all of these in the well cost figures that they discuss with the analysts in Wall Street. Looking ahead, keep your eye on several key trends as we seek to achieve our $8 million target cost. On the positive side, drilling cycle times in the Bakken continue to come down as we move to more pad drilling, and as our record improves in key performance indicators like geosteering, downhole motor performance and bit technology. We've reduced our drilling spud to TD cycle time by 20% or 4 days from the second quarter of last year to the second quarter of 2013. Our average lateral drilling time has improved by 30%. And the time and cost of rig moves has been reduced significantly as we've transitioned to more pad drilling. We're also working to reduce costs in such areas as site construction, equipment and tool rentals and completion material cost. We're focusing intently on our supply chain management as our activities continue to ramp up. With 70% of our operated rig fleet on multi-well pads, we expect additional cycle time and cost improvements. On top of our efforts, our midstream partners are doing a great job building out infrastructure ahead of large pad projects so we can maximize the delivery and sales of produced oil and gas. Those are the positives working in our favor. There are also trends in the other direction. Completion pricing have flattened, and in some cases, we're seeing upward pressure. Thus, we continue to look at our processes. We're definitely seeing incrementally higher costs as we experiment with innovations and completion methods, primarily around slick water or gel slick water hybrid fracs with increased concentrations of ceramic proppant. We believe that the successful these jobs could have the potential to unlock novel technical solutions to actually improve margins in this play. Similar gains will be made in SCOOP. We've seen significant improvement in well costs mainly due, once again, to more efficient geosteering and other performance-related improvements. Average costs last year ranged from $9 million to $9.5 million for operated wells in both the oil and condensate windows, respectively. Today, we're seeing those costs in the range of $8.5 million to $9 million for our 1-mile lateral in SCOOP. We've seen an increasing opportunity to ship across unit wells over time. We're not completely there yet, but for $13 million to $14 million per well, we should generate twice the production in EUR or more on average for 55% to 60% of an incremental cost. That's a significant boost to our capital efficiency. I hope this gives you a better sense of how we're improving efficiency and reducing costs as we continue driving toward our 2013 production growth and other operating targets. And with that, I'll pass it over to our CFO, John Hart.

[John D. Hart:]

Thanks, Rick. Let me run briefly through several mid-year financial metrics. Adjusted net income for the second quarter was $1.33 per diluted share, beating the Street consensus by $0.08, largely on the back of higher production. EBITDAX also increased to a record of $708 million, which was up 14% from the first quarter and 5% higher than the Street consensus. Our cash flow for the second quarter was also considerably stronger and improving. Cash margin was 73% for the second quarter as we continue to lead our oil-concentrated E&P peers. Our hedge program is critical to our growth strategy to assure that oil price volatility, which we've certainly seen plenty of that, doesn't disrupt the momentum of our drilling program. This is important in achieving our 5-year growth plan. Our June 30 hedge position is laid out in the Form 10-Q, which was filed last night. We took a slightly larger-than-usual one-time impairment in this past quarter, which relates primarily to our Niobrara exploration program, which hasn't met our expectations. Second quarter 2013 production expense was $5.86 per Boe, slightly higher than 2013 guidance. But this mainly reflects slowdowns due to adverse weather in the Bakken and an increased number of workovers. The monthly trend improved sequentially through the quarter in part due to improved weather in June. June production, for instance, the expense per Boe was below the midpoint of our annual guidance as we continue to focus on improved operating cost. Our other guidance metrics, production taxes, DD&A, G&A expense and equity compensation per Boe are within guidance ranges for the year and trending towards the low end of our ranges. Total long-term debt was $4.4 billion at June 30. So our net debt to EBITDAX ratio was 1.75x on a trailing 12-month basis, and 1.5x if you annualize the second quarter's EBITDAX. As our spending in excess of cash flow continues to narrow, you should expect to see an even further improved net debt to EBITDAX ratio by the end of 2013. First half non-acquisition CapEx was $1.8 billion in line with our disciplined growth strategy. The CapEx overspend versus cash flow continues to move in a positive direction. In fact, our expectation is for our outspend in excess of cash flow to continue to trend downward throughout the remainder of 2013 and throughout 2014. We are focused intently on capital discipline and growing production and proved reserves. Bottom line, we're on track to achieve our guidance goals for 2013. With that, I'd like to turn the call back over to Harold.

[Harold G. Hamm:]

Thank you, John. If I could just offer my own perspective of what we're currently involved in today for everyone very briefly, from my own experience over the past 46 years, we're witnessing firsthand a great evolution of our industry due to the horizontal tight oil development and multistage completions from previously bypassed reservoirs such as the Bakken, Woodford, the Eagle Ford and Permian Basin formations. For companies such as Continental who have been focused long term in oil development and are well-positioned to participate in this evolution, the future is extremely bright and promising. We are very excited at Continental to play a part in this renaissance. In closing, I'll summarize our first half of 2013. We're halfway through a very successful first year of our 5-year plan and we're on track to achieve our 2013 goals. In the second half, you should expect more the same in terms of operating and financial highlights, further delineation of the Lower Three Forks and SCOOP, strong production growth, increased cash flow, strong net income growth, capital discipline and an increased proved reserves as we further prove up the reservoirs that we have in the Bakken and SCOOP. We're getting it done. And obviously, Continental's achievements are reflected in increased share price and valuation. The entire team is focused on maintaining Continental's industry-leading growth in our 2 premier oil plays. To that end, we're currently working on our 2014 growth plan and look forward to sharing that with you in the fall. With that, I'll hand the call back to the operator to begin our Q&A. Thank you.

[Operator:]

[Operator Instructions] And our first question will come from the line of Drew Venker with Morgan Stanley.

[Andrew Venker:]

I was wondering if you could give us some clarification on the Lower Three Forks exploration program and whether you had drilled all of your Lower Three Forks wells below existing Bakken and Three Forks producers?

[Harold G. Hamm:]

Yes. We've got a table out there summarizing what targets we are shooting for here. But yes, this whole program has been targeted evaluating the Lower Three Forks, which includes the TF2, TF3 and TF4. We do have a -- 4 wells in there that are TF1 1 wells that we are drilling that are part of that program to -- that we are basically in the program as interference test wells. And essentially ensuring as we -- as Rick had mentioned in here, what we wanted to do at this program was, first, delineate the productive footprint or basically determine the productivity of these lower zones. Because before we started this, there really was no production from these lower benches. And so we've succeeded really, in part one of this, which that is demonstrating that we've got a productive footprint that covers at least to this point, 3,800 square miles. And so part two of this now is to demonstrate that the reserves we're getting here in production are incremental to the play. That's been a big question out here. So we're 65% through drilling all of these wells and are just proceeding ahead as planned. And the results we've got at this point are very encouraging because we're seeing consistency of results within areas with the TF1 production in the areas, and really just the widespread nature of the performance that you think about it in this basin when you combine what Continental has done, we've got 14 producers and then you can add to it the wells that have been completed by other operators out here. There are a total of actually 18 Lower Three Forks. And that would be TF2, TF3 and TF4 producers within a 3,500 square mile area. And the odds of us getting out here and drilling those -- that few wells in that large of an area and getting these kind of results that we've incurred is, I think, gives us a lot of confidence in the overall extent and continuity of the play.

[Winston Frederick Bott:]

So Drew, if I -- just to add one small point to make sure we answered your specific question. For the wells that are being drilled in that program, they are in units that already have a well in them, not necessarily both TF1 and the Middle Bakken, but there's another well in those units. And they're also very close to the core control that we had.

[Andrew Venker:]

Okay. So I guess to clarify, was really getting at in the Colter unit you have, and I think that's definitely true on that eastern part of the basin, there's a lot of vertical fracturing. Just curious if this is on a similar basis, the rest of the tests you've done, whether they are relatively vertically stacked within 600 feet or 800 feet or so?

[Harold G. Hamm:]

Okay.

[Winston Frederick Bott:]

Actually the answer to that is not necessarily for the exploration program for the deeper bench. That is essentially to prove commercial production over a broad area. When we get to understanding how they're vertically stacked, that's more aligned to the density projects that -- and we're doing 4 of those. And those are shown on the map as well. That's where we're getting the additional data to understand the actual -- what's appropriate for full field development.

[Andrew Venker:]

Okay, okay, that helps. And on the eastern side, where you're seeing this extensive vertical fracturing, can you give us an idea of how much acreage you think has similar vertical fracturing? Or how much acreage exposure you think you have?

[J. Warren Henry:]

Drew, it's way too early to have a feel for that right now. I was trying to put it in perspective here, when you've got 18 producers over a 3,500 square mile area, it's very, very difficult to go to that detail at this point.

[Operator:]

And our next question will come from the line of Leo Mariani with RBC.

[Leo P. Mariani:]

Just question on the Charlotte unit, trying to get a sense on a few of these wells where you've got a Three Forks 1 and a Three Forks 2 slightly offset and then a Three Forks 2 and a Three Forks 3. Can you give us the distance between those 2 well pairs?

[Harold G. Hamm:]

Yes. If you look at Slide 6, I don't know if you happen to have that, but I'll give you -- just to explain, okay. If you look at that, you see the 2 pairs of wells that are circled there. And on the left-hand side, on the west side of the unit there, you've got a TF1 and TF2 producer. And those are 660 feet apart laterally. And vertically, they're going to be about 50-foot apart, the 2 wellbores. The same, if you go to look on the east side of the unit there, the 2 well circles are TF2 and a TF3 producer. And those are 37 feet apart vertically and 660 offset laterally.

[Leo P. Mariani:]

Okay, that's helpful. Just trying to get a sense of how this differs on the spacing from what you saw at the Colter unit here.

[Harold G. Hamm:]

Yes. If you slide over to the Colter on the next slide, on Slide 7, there you can see that the TF1 producer that had been there for 2 years and produced 230,000 barrels of oil equivalent was -- it's 660 away from the TF2 producer laterally and 68 feet vertically separated from the TF2 producer. And so there is a common pair there that's very, very similar to what you have over in the Charlotte as far as its distance between vertically and horizontally. And in the Charlotte, you can see we've seen no evidence of production interference. However, in the Colter, we have seen evidence of production interference. In fact, it's direct evidence of production interference here. And that direct evidence is, number one, we -- these wells, the TF2 and the TF4 well, were not capable of flowing, okay. So that indicated lower bottom hole pressure. And the second thing was that we actually saw frac sand show up in our Middle Bakken producer. And so that's directive. And so evidence here is that we have some more robust fracturing in this particular area here at the Colter that doesn't exist in the Charlotte. And where we have this fracturing, we've essentially -- Mother Nature has enabled the communication of these various layers and benches. Because historically, we have over 100 pairs of wells that have been drilled out in the basin between the Middle Bakken and Three Forks 1,660 offset. And there's no evidence of communication. But here, we've seen across the lower Bakken Shale all the way to the TF2, we've seen communication between these wells. And the evidence itself is what it is. I mean, it's -- you can see that it's here. So why is the question. And again, I think we're on the Nesson Anticline here. And this is an area that's just structurally more active. And in those areas, you're going to have areas of more intense fracturing. And those areas, we're actually getting assistance from mother nature for connecting multiple layers in here.

[Leo P. Mariani:]

Okay, that's really helpful on the explanation. Another quick question for you guys. Just looking at completions and looking at your numbers, I'm seeing that you guys did 138 completions in the Bakken in the first half of '13. You guys are guiding to 245 net for the year. So should we expect to see completions decelerate in the second half here? And then kind of the same question on the SCOOP. I'm seeing about 17 completions in the first half of the year and you guys are guiding to 55 for the year, so that kind of implies an acceleration. Can you just walk us through sort of the dynamic there? Am I looking at this right?

[Richard E. Muncrief:]

You are. This is Rick Muncrief. You are. We are -- as you look at their pads, Rick Bott mentioned earlier, we have the 4 density projects. You're going to see the completion slow down somewhat in the Bakken. And we currently have a backlog of about 75 wells that have been drilled and have not been completed yet. And that backlog will grow slightly throughout the second half of the year. And so you're looking at it properly. And that's all a function of the pad drilling with our large pads. Down here in SCOOP, you once again are looking at it correctly. And that we currently, as of today, we have 10 rigs running in SCOOP. And we'll add a couple more rigs. And we'll be working at inventory down. We have -- we typically will have somewhere between 6 and 10 wells waiting at any given time. Some of that is around infrastructure buildout and just trying to time that.

[Winston Frederick Bott:]

So one thing that sets us up for is larger completions going into the first half of 2014 from this backlog.

[Richard E. Muncrief:]

That's correct.

[Leo P. Mariani:]

Okay, that's really helpful. And I guess just last question on crude by rail. You guys clearly are still railing quite a bit of your barrels here, as you mentioned. Obviously, we've seen a big compression in the Brent/WTI spread, which I guess clearly will hurt coastal pricing versus Mid-Con pricing. Just wanted to kind of get a sense of what you guys are doing on the marketing side to maybe address that? And what your ability is to maybe limit some of the volumes by rail and send more by pipe or other means?

[Harold G. Hamm:]

Leo, we still have some markets that have like a pretty broad fare. They're just premium to the WTI yet. And certainly to those, we're going to keep shipments going. And we need rail to get the volume of oil out there. So this premium we get is certainly helping us offset transportation cost.

[Winston Frederick Bott:]

And also, I'd just add to Harold's point there is let's also keep it in perspective that both of these prices are nice prices no matter what benchmark you're looking towards. The netback to the well is nice in terms of translating down to the bottom line.

[Operator:]

And our next question will come from the line of Doug Leggate with Bank of America Merrill Lynch.

[Douglas George Blyth Leggate:]

I've got a couple, if I may. And my first question, I guess, is to Rick Muncrief. Rick, as you've been talking about connecting different benches on the eastern side of the play, on the Colter unit, does that change your view of recovery rates on the Bakken wells in not cited the play versus your 600 tight curve?

[Richard E. Muncrief:]

I don't think it changes our global outlook on things. We're going to be, as we mentioned earlier, we're going to be learning a lot over the next 12 to 24 months. And what we're seeing and reporting thus far are some of the early indications. And some of those indications have been extremely positive, as Jack Stark mentioned earlier. And we can't help but be excited about it. So from our perspective, I don't think it really changes our outlook on our 603 model. Over time, you may see that as you go to increased density, that may come down a little bit. You would almost expect that. But we'll just see how that all plays out. Once again, I think we're going to learn a lot not only with -- here at Continental, but across the industry in the next 12 to 24 months.

[Douglas George Blyth Leggate:]

Again, it may be a little early, but as it relates to the Three Forks tests and the 5 other areas, does it -- can you give any indication as to whether those -- how those tight curves look relative to that 603 model also? I realized that's the Middle Bakken model, but...

[Richard E. Muncrief:]

Right. Well, it's actually the Middle Bakken and the TF1 model. We really have the same model. We have looked across the base on some of the early indications. And what you see is a real nice bracketing of those curves. In some cases, we have wells that are considerably above the 603 model. And then we have some that are quite honestly below that 603 model. But when you put those, layer those on and overlay those with a representation of the 603 from a rate time perspective, it's a real nice bit. It really is. So at this time, we're really, really encouraged. But once again, we're 120 days into this.

[Douglas George Blyth Leggate:]

Right. Maybe for Rick Bott, if I can squeeze in another one. Rick, we've talked about -- you talking about your wells or at least having your IP rates obviously impacted by that. There's a lot of new infrastructure, it seems, coming onstream towards the turn of the year. I'm just curious as to whether you would have a slightly -- any change in philosophy as a 2-stream maybe going to a 3-stream and opening those wells up a bit and -- I'll leave it there.

[Winston Frederick Bott:]

Well, it all has to do with the line pressure for the gas you're putting into the line. At the end of the day, we are getting better infrastructure built out there. I'd say the key for us is, in terms of that, choking back the wells, that is mainly -- I mean our goal is we're not -- we're of north and south. We're all the way across this play. Our goal is to get good engineering science and good data to try and understand the ultimately best way to develop this field, not to maximize an initial IP rate for a headline. At the end of the day, the line pressure which you can put the gas into the line is important for us. And we make sure that we're able to sell gas first. So we have our wells hooked up when we test them and flow them. And that is essentially the choke-back that I was referring to in terms of making sure that we're able to capture the value of that gas, not flare it and get it right into the line. In terms of ultimately whether or not we've pretty much established a fairly standard choke size for production across the basin, and that's not really changed. So I don't see any real change to our strategy at this point in time.

[Operator:]

And our next question will come from the line of Pearce Hammond with Simmons & Company.

[Pearce W. Hammond:]

My first question is if you can provide a little more color on the acquisition and capital expenditure in the quarter for about $101 million?

[Harold G. Hamm:]

Some of this has obviously gone into plays that we're not ready to talk about. So we're going to have to leave part of that just unsaid at this point.

[Pearce W. Hammond:]

Okay. And then on that long-lateral SCOOP well, what was the cost there?

[John D. Hart:]

Appears that, that cost came in at I believe $13.8 million. And 9,500-foot lateral was actually one of our areas that is a little more on the fringy side. And we're very pleased with the results of that.

[Pearce W. Hammond:]

Great. And then, Rick, in the Bakken right now on kind of a leading edge basis well cost. I know in the past, you published that Florida-Alpha pad at sub-$8 million per well. Where are you right now on a leading edge basis on your well cost in the Bakken?

[Richard E. Muncrief:]

We have seen some individual well costs at $7.5 million on an individual well cost basis.

[Pearce W. Hammond:]

And then last one for me. Right now, you've got about 70% of your rigs on pads in the Bakken. What do you think for '14 that percentage could be?

[Richard E. Muncrief:]

It's probably going to be in that 70% to 75% range at any given time, maybe a little higher than that. But I think 70% to 75% is a good spot. We still have got some areas to HBP quite honestly.

[Winston Frederick Bott:]

Yes, if I could just pick up on 2 of your points, questions that you asked. That acquisition capital that we talked about, just in case you were wondering, there wasn't any production associated with that. So that's one point. And the second point, on well costs, Rick might want to comment, we're continuing to drive down costs all across the basin. And we've got some real edge game-changers in Montana. You want to...

[Richard E. Muncrief:]

Right. Pearce, in the $7.5 million was a North Dakota well that we've seen. On the Montana side, we've seen them at $6.4 million on a completed well cost.

[Operator:]

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

[Noel A. Parks:]

With the news of your Three Forks well working, it makes me think, as you go forward and think about the time when you're going to be developing across all the different benches, how do you prioritize locations where you might have, say, 5 producing zones versus others where you might have fewer, but I guess the process of just crowding a bunch of different wells onto the same section might be easier. I mean, could we see a day where essentially, in one part of the basin you're doing Middle Bakken and second Three Forks and then another part of the basin you're doing first and third?

[Winston Frederick Bott:]

It's a great question, Noel, and very insightful. I think it might be a little bit too early to give you any guidance. But I can envisage that there, once we get a little bit better understanding and get through the various testing programs we have for the Three Forks, the deeper bench testing and also these pilot density projects, is that you could have multiple wells. And they might even have different spacing intervals in different intervals if we see more of that vertical connection that we see in fracturing. But I'd say, as we move into full field development it'll be 3 primary drivers

[Noel A. Parks:]

Great. And just as perspective on sort of legacy Bakken holdings you have. If you can refresh my memory, how much of the Three Forks or how many of the different Three Forks zones are in place, say, across Elm Coulee, for instance?

[Harold G. Hamm:]

Noel, we've -- over there, you've got a bit of the Three Forks 1. And then you do have the 2, 3 and 4 present. But as you get up towards Elm Coulee, their faces change and they go on in the third and fourth in particular, where you really start getting anhydritic. So those do become less prospective, but you still end up having the TF1 and TF2 as possible candidates down the road.

[Noel A. Parks:]

Okay. And I wanted to turn to SCOOP for a minute. I think you mentioned a minute ago that the long lateral you did out there was actually in sort of a fringy area. So it sounds like it actually performed better than you might have thought going in. Can you sort of update us on your thoughts on the footprint of the SCOOP? And where you think you pretty much have the definition established? And where do you think there's still a frontier to find out there?

[Harold G. Hamm:]

Sure. If you could go to Slide 8, that shows the SCOOP fairway. And as Rick had mentioned earlier, we've really focused most of our efforts in the 40-mile stretch that's in the northwest part of this fairway. And what we see as potential here is that we feel we can take this trend another 40 miles to the southeast. And on this Slide 8, you can see there's green, which is the oil window. The orange is the condensate window. And that pink color is the gas window as best we know it today. And we continue to work at defining that and delineating it. As we get more data, it becomes more well-defined. But that's really our vision here. And so we are planning and are in the process of beginning to test our lease blocks down in the southeast extension of our existing proven or de-risked area.

[Winston Frederick Bott:]

And Noel, with your permission, I'll just add a point of perspective. And we've talked about this on previous calls. This is essentially represents our leasing. It's following essentially the leasing pattern that we had. We understood the play first in this area, and then leased down to the south. And so we're really essentially mainly testing these ideas and moving through an HBP program. A program here, as we talked about before, is to really make sure that we follow on and hold these leases. So to the point is, we're just as excited about what we have in front of us as we are about what we've already discovered.

[Noel A. Parks:]

Great. And just the last one. Could you comment on what you're seeing for first year declines in the SCOOP and how the economics look like they might stack up against the Bakken sort of over the long term?

[Richard E. Muncrief:]

Yes. We see some variability on the decline. We've seen somewhere between anywhere from 25% up to 60% in the first year of production. From an economic standpoint, we think that the SCOOP economics are – range from the high 30s up to 80% type rate of return numbers. And so you compare that with the Bakken. In a lot of cases, it compares quite favorably to the Bakken. And so we're just real excited about what we're seeing down there. Earlier, when I mentioned the Singer well as being somewhat in a fringy area. The fringy area was still then the 40% rate of return. So in essence, we think cross unit, takes that from a 40- to a mid-60s kind of rate of return.

[Operator:]

[Operator Instructions] Our next question will come from the line of Ryan Todd with Deutsche Bank.

[Ryan Todd:]

One question on the SCOOP. You talked about adding a couple rigs in third quarter. How should we think about the potential for continued acceleration into year-end? And is there a type of run rate that we should think about in the medium term?

[Richard E. Muncrief:]

I don't think so. I think the 12 rigs is where we need to get to deliver this year's program, stay within our capital guidance. And then as Harold mentioned in his some of his comments, we'll be laying out our 2014 plans sometime this fall.

[Winston Frederick Bott:]

Yes. So in terms of the exit rate, I think it's -- I think as we've guided to the upper end of the guidance, you might just look at where we started at the beginning of the year. And 38% to 40% growth on that is where we'll finish the year.

[Ryan Todd:]

Great. And then if I could ask one on the Bakken. And I apologize if I missed it. But I wasn't sure if anybody has referenced this. But are you doing -- how much work are you doing on adjusting your well completions in the Bakken on experimental-type completions? Any thoughts or takeaways there yet? And how much -- is there much of an impact on well costs, would you imagine?

[Richard E. Muncrief:]

Yes. We're going to experiment with some slick water jobs and also some hybrid jobs. But just the slick water jobs, some of the numbers we've seen could be as much as $1 million per well higher, depends on the size of the job. It's just not the pumping cost, but it's just the all-in cost. And our team is looking at pumping a few of those and see if we see any difference in productivity. And that's the thing about our business. And it's all about continuing to improve your processes and your approaches. And so we'll keep you posted as we learn more.

[Winston Frederick Bott:]

Yes. And I'd link back to Harold's comments. I mean, this is still very, very early days in understanding this horizontal oil renaissance and addressing these reservoirs that have never been producing well before. So it's very early days. And there's -- we're optimistic that there's lots of technology and lots of great ideas yet to come.

[Operator:]

And our next question will come from the line of Joe Allman with JPMorgan.

[Joseph D. Allman:]

Just a question on just interference in general. So when we think about interference you're seeing among the various intervals, what are the positives of interference and what are the negatives of interference? And then following up with that, for Rick Bott, I mean what have you seen, and this may be repetitive, what have you seen in the Lower Three Forks testing that is encouraging to you? And then what so far has been disappointing?

[Winston Frederick Bott:]

I might just comment briefly on what the positives of interference. In some of these -- this area, of course, along Nesson Anticline, tremendous produceability in some of these wells. We've seen wells, 2 million barrels EUR or greater. So the connectivity that Mother Nature can give you can be very good. We need to understand it from an increased density perspective. And so that's the data that we're getting in regards here. Other areas won't have this. All the movement perhaps that causes fracturing, and -- but we need to understand it. And that's what some of this is about. The second part, someone else?

[Harold G. Hamm:]

You want to address the negative?

[Richard E. Muncrief:]

Well, the negatives would be that if you go out and you have unplanned interference, you probably just spent some capital that you don't have a preferred rate of return on. And a positive would go -- is the inverse of that, that you may be able to understand your reservoir, optimize your capital spend over time as you develop this and deliver great program economics.

[Winston Frederick Bott:]

Yes. So Joe, let me then just add to both of those points then, and also think in the long term and the big picture. So there, on the Nesson Anticline, we've got enhanced fracturing. Predicting is important. What that means is, as Rick and Harold both alluded to, on a primary recovery, we can probably get that oil with less capital, fewer wells, less capital. Ultimately, you may also want to look at where we go through to, for enhanced recovery, secondary and tertiary recovery, and you may still need density of wells drilled. If you drill those and get the recovery in primary, the economics for an enhanced recovery always look better. But at the end of the day, we're looking at maximizing this recovery. We've talked before about what the ultimate recoverable is from this play. Continental's put out there some numbers using a recovery factor of only getting 3.5% of the oil out. If we get that up to 5%, 7% of the oil with some of these enhanced recovery ideas that are in the future yet to be tested, then there's a large prize for us to capture. So part of our efforts we're doing now is for near-term understanding in primary development, but also building our understanding for the future. Then you asked about Lower Three Forks, the encouraging and disappointing? Well, I'd say in terms of disappointing first, we would have been really nice to be surprised if the core data ended up being anomalous, and we had better reservoir than we thought that was out there. But it actually looks like, if you take it on a percentage basis, the core program that the exploration guys designed really did give us a pretty good understanding of the basin. And so quite a bit of this is coming in, in terms of our model. And I'm not really disappointed by the lower production rates in the Three Forks 4. It looks that way now, but again, back to Harold's point and that vision he's got is that this is the first few years in a multi-decade understanding of how to develop unconventional oil in the horizontal oil play, tight oil play. And so I'm quite confident that we will, in time, figure out, both in terms of efficiencies and in terms of technology to be applied, ways to produce that oil. The big takeaway and what we tried to determine in this program is, is it full of oil all the way across the play or should we expect water in those intervals? And the good news is, it's full of oil. The second good news is, is there are these good producible dolomites that we already know how to frac pretty well in all of those intervals. There will be some -- there will be heterogeneity within them across areas, but the change is relatively gradual. And so we think it's going to be quite predictable. And so we're upbeat. We just know we've got a lot of work to do there.

[Joseph D. Allman:]

Okay, that's helpful. And does the -- do the data that you gathered and in particular the interference data, does it cause you to rethink your drilling and completions of your primary wells in your acreage?

[Winston Frederick Bott:]

Well, there's a couple of things that we probably are going to look at and think about testing, and it's probably really too early to lay out that out there for you because we need to let the engineers and the geoscientists do a little more thinking. But we're always challenging our -- even our own internal conventional wisdom to make sure that we're pushing the envelope and making sure we're getting the right data to be able to answer those questions. So I'm very excited about these density pilots. We're doing some new things there. We talked only about the microseismic, but there's a lot of things we're doing in the completions that if they prove out, will -- may cause us to go back and think about how we develop. And that's why we talk -- the headline we use is we lump in the statement, full-field development, but that's what we mean, is how we're going to prosecute the development of a given area and we're thinking about sort of a township development. How do you -- what's the most efficient and effective and cost effective way to responsibly produce within that township. And that covers a large area. And so the guys are working on that, they're coming up with a lot of ideas, all the way from what's going on in the subsurface, to how they operate and how they, even down the road, end up working these wells over. So there's a huge effort going into understanding this and the planning that'll come out of that. Rick, you want to add anything to that?

[Richard E. Muncrief:]

No, that's fine.

[Winston Frederick Bott:]

Jack, would you like to add?

[Jack H. Stark:]

One thing I might add there quickly, Joe, is that in those areas where you have interference is a great area for acceleration of production. And also, not only -- it's impactful in 2 different ways. First, of course, production. The other one is the information we're getting on reserves as we go forward with this increased density. So they're very impactful in both of those areas.

[Joseph D. Allman:]

Okay, that's very helpful. Just a quick one for Rick Muncrief. I think, Rick, you mentioned completion cost increasing. Were you just specifically talking about completion cost increasing because of the way you're doing things or are you also citing some pressures in kind of the service cost pressure just because of capacity or what have you?

[Richard E. Muncrief:]

Well, I think you have 2 components there. And the first is we think, in a lot of the cases, some of the pricing has bottomed out, and so what it causes us and our service providers to do is look at unique ways to work more closely together to drive out inefficiencies, and thus, we'll see lower cost from that. The second part is where we've seen the opportunities for us to try some of these different approaches to our stimulation. For instance, I mentioned slick water fracs up in the Bakken, where we would use 100% ceramic versus our traditional 60-40 where we're pumping 60% sand, 40% ceramic. You'll see some additional cost on those particular jobs, and then we'll just evaluate the results of those jobs and adjust or not based on those results.

[Operator:]

And our next question comes from the line of Hsulin Peng with Robert Baird.

[Hsulin Peng:]

So I have a quick follow-up to the type of experimentation you're doing with completion stimulation. So I guess how much experimentation have you done? And have you seen evidence of better production EUR from your experimentation? And just trying to understand a little bit in terms of the cost versus incremental return from that experimentation.

[Richard E. Muncrief:]

Hsulin, we have not done many of those yet. We're still early on. We're going to be pumping a few more. Actually the team was meeting again today to finalize some additional design parameters. And it's just something we'll just have to share with you in the future. We really don't have a lot of data today.

[Hsulin Peng:]

Okay, no, that's fair. And then second question is on the SCOOP. So the -- on your first cross-level well, the 1,915 IP rate, given that you mentioned that you expect production to double, I was just wondering, for modeling purpose, is the 1,915 a good IP rate? Or do you expect that number to increase given that it's also in the fringier area, like you said?

[Richard E. Muncrief:]

Well, that is -- that was the actual production average for the first several days of that particular well. We think that's pretty indicative of that area. And we've also had some -- if you look at the map on Page 8, you can see where that Singer well, which is in the northwest piece of our acreage in that particular area, central part of our acreage. If you go to the southeast, you see a number of black dots, those are producers that we have drilling completed and that's a very nice area for us, and those rates, we've had several 640s. So our 1-mile laterals have had rates similar to that. I mentioned -- you'll see that Vanarkel right above that is -- or excuse me, right below that, is a 2,000 Boe per day rate from 640. So we're encouraged by what we're seeing in that area and then we're also encouraged by the fact that we were able to drill that first nearly 10,000-foot lateral from spud to TD in 53 days, and went -- the job went very well. So we're encouraged about what our cross-unit opportunities in the future look like.

[Hsulin Peng:]

Okay. And then last question, just crude by rail marketing. Given the compression we've seen with Brent and WTI, I was just actually wondering, are you seeing lower rail costs to sort of make up for that compression? And just kind of can you comment on that?

[Winston Frederick Bott:]

We sure can, Hsulin. We have not seen any reduced rail costs yet. However, we anticipate, as we talked about, that, that -- those differentials will be volatile and they will have probably moved considerably when the additional pipelines that have already been planned and published, when those come out, so you'll see a lot of -- you'll probably see those things move around quite quickly when those things come onstream and the market readjust. We -- to handle that volatility, we have adopted this portfolio approach and we try to maximize what we can do on spot as often as we can so that we can take advantage of those and be as agile and nimble in the market as we possibly can. As well as continuing our efforts working with end-user refiners, helping them understand the value of the Bakken crude, the consistency of the Bakken crude and our ability now as the largest producer to get them a growing supply, also our ability by rail to get them a barrel that is unblended and therefore, they can count on the quality. So in the future, we do anticipate that rail -- the whole package of rail costs will come down because we think rail has a long-term home in the distribution of crude within North America because of the differences and optionality that it provides you, but it will have to be cost competitive with the pipelines as those come on and as they reach the major refining centers.

[Operator:]

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

[Brian M. Corales:]

Just a question on the pilot programs. When did those come on and also, have you all seen anything -- I don't know where you are on the drilling side, but to -- have any of those wells you've seen not over-pressured reservoirs like you may have seen in Colter?

[Winston Frederick Bott:]

To your first point, the Hawkinson comes on in the fourth quarter and then the other 3 density pilot projects will come on from the beginning of the year through the end of the first quarter. We have not seen any interference issues yet, and that is because we are drilling these all at one time on each pad and then we will clean them out all at once and put them all into production at once. So we won't have that data, Brian, until we actually go to production and put everything through and then get it all on. So it'll be sort of coming in big batches of information as well as production, if you will. So unfortunately, there's no information yet in terms of interference. I will say that in all those units, as we drill them, we're getting good shows, the type of shows that we expect, and so it's the type of thing that makes you confident that you're on the right track.

[Brian M. Corales:]

Okay. And so you also get a real big surge production kind of throughout the first quarter of next year?

[Richard E. Muncrief:]

That's correct.

[Winston Frederick Bott:]

Yes, sir.

[Richard E. Muncrief:]

Brian, it's Rick Muncrief. One other pad I may mention is one that is not either a lower bench test or is a interference test, that's our Atlanta pad, which is in a nice area as well, and they're in Williams County. It's 14-well pad. We've got the first 11 wells drilled. Actually, the first 2 wells we drilled are now in production. We did simultaneous operations there. We actually got a chance of host the Secretary of Interior earlier this week and real proud of what we're doing there. And so that's another pad that you're going to see coming on about the first of the year and we will see some nice production growth coming out of all of those.

[Brian M. Corales:]

Is that going to be the new norm, 14-well pads?

[Richard E. Muncrief:]

Well, we've got pads that go from 4-well pads all the way up to a couple designed to have a 2 on the front of them. We're still trying to finalize those, so pretty exciting.

[Operator:]

And our next question will come from the line of Marshall Carver with Heikkinen Energy Advisors.

[Marshall Carver:]

So the well costs in the Bakken are coming down a little more than expected, faster than expected. In the past, you talked about using some of that savings to accelerate in the SCOOP, but we're not seeing any changes to the SCOOP completions per the press releases from Q1 to Q2. Do you think there's some downside potential to the CapEx guidance for the year or an uptick to the SCOOP completions number? Or is it more that you're going to be drilling wells in the SCOOP but not completing?

[Jack H. Stark:]

Well, we've been for sure making sure that we're right on target with our budget, and that's working out very well. There is some adjustment among the program. Our savings in the Bakken has allowed us to do some more longer laterals, [indiscernible] in the SCOOP and drill another well or 2 in SCOOP and we're seeing production ramp up accordingly in the SCOOP area. So anyway, there is some adjustments in the program, and that's why our production guidance has moved up.

[Winston Frederick Bott:]

Just one point, too, Marshall. I think we gave you all those net well additions last quarter when we talked about the major savings we achieved in the Bakken to get more net wells and we're going to ramp up faster in SCOOP. So that news is kind of already out there. We told you about that last quarter, and so…

[Marshall Carver:]

Well – okay. In the Nesson Anticline area, about how -- what percentage of your Bakken acreage is in that area where we would expect to see the more pressured rock?

[Harold G. Hamm:]

We have pressured rock across of much of the basin. What we're seeing on this anticline, of course, is more natural fracturing due to the structure. So Jack, you want to answer that the numbers?

[Jack H. Stark:]

Yes, Marshall, this is a Jack. If you go to, say, like, Slide 6, there you can see the Nesson Anticline, this is a structure map, and it shows the Nesson Anticline along that arrow, and that is the area of more intense structuring, and you can see where our acreage lies along that. So right now, you can look at it, and it's a small percentage of our total acreage when you look at what we have to the north and into the west of there. But what I want to caution about is that, in here, when we look at these like the Colter, we have an area here where we have fracturing, but take into consideration the well to the west that was drilled here, that Three Forks 3 producer that was completed in the Colter unit, and it is producing from virgin reservoir pressured rock. And so these areas of fracturing might be very localized and I expect that they are, and therefore, you will have some of these areas that we have may be linear in nature and could run for several miles, but they may only be 0.5 mile wide. And so you're fortunate when you get into these, but the question we have right now is just how pervasive are they. And so we're acquiring 150 square miles of 3D data as we speak right now across our Hawkinson and Colter area, and hopefully that will help us be able to better define these type of fractured plays. But if you -- I just mentioned, there's a well out here that kind of depicts -- is kind of the poster child for fractured producers out here, it's the U.S.A. 2D-3 that Petro-Hunt drilled very early in the play, and that well has produced 1.4 million barrels and is still doing, I think, 200 to 300 barrels a day, and that well was never fracture stimulated, it's producing from a natural fracture zone. However, there's a bunch of wells drilled around there that had never seen any production like that. So these fracture trends can be very localized and very sweet when you're in them, but -- so we've got a lot to learn. We've only got 18 producing wells out here as I said before in these lower benches, and so we've got a long ways to go, but we're proceeding ahead.

[Operator:]

And our next question will come from the line of Paul Grigel with Macquarie.

[Paul Grigel:]

On the down spacing front, as you guys look to the back half of the year and into the first quarter of 2014, what do you need to see to confirm the success or the challenges in terms of microseismic and production history? And what level of EUR decrease would be acceptable for the program?

[Harold G. Hamm:]

There's a lot of questions in there, we may miss some of them, but let's try. Well, success, of course, is going to be a nice big production bump, that's the near-term success. I think the key for us then is to look at that over probably 0.5 year and just look between the various wells and see if there's any differences and then try to tie that back to the way we understand the fracture system and the completion technology. Now the microseismic and 3D seismic isn't going to play into that because that's going to help us then. As I said, with this really interesting way we've designed the microseismic, we're now able to triangulate and watch these fractures grow and look at the length as well as the direction. And then you've got to model that over time as the pressure comes down as you produce these. So there's going to be a lot of information here for us to pull together to determine how best -- and this is all really trying to determine how best we can go out and plan kind of full-field development in the areas I talked about before that have the best rate of return in maximizing our operating efficiencies. So we're quite bullish on that, but we just got to wait for those results. I think Harold had something to add.

[Harold G. Hamm:]

I might add something. You mentioned EURs and what was acceptable to us. You have to understand within those units that, number one, you're drilling on acreage already paid for then by the first well; number two, you've got facilities already in place, that's area by the first well. So obviously, you could sense some lower EURs. We don't expect that in these lower benches. Very early result shows similar type of production in those and this is -- the natural thrust of producing these lower benches, we obviously had a lot of production in Three Forks 1 and a lot of history with it now since we first drilled our first well there and started everybody on this course. The second and third benches, I think, we'll get just as efficient in those completions as we have in the first one. So we expect I wouldn't say decreasing results, and decreasing EURs going to occur here.

[Paul Grigel:]

Okay. And then on the -- just a quick follow-up on the Three Forks 4 test. Only doing a couple in this program, would it be fair to assume that in 2014, there'd be additional either 3 or 4th bench tests occurring as well?

[Jack H. Stark:]

This is Jack. Yes, there sure is. We will obviously monitor results, but we're also continuing to put together our stratigraphic model across the basin here and mapping out these various benches and where we feel it is warranted, we will probably have a few more tests to test the viability of the 4th bench.

[Operator:]

And our next question comes from the line of Andrew Coleman with Raymond James.

[Andrew Coleman:]

The question I had was, as you think about the design of the microseismic, could you elaborate just on, I guess, the number of locations that you're putting all the different monitor wells or monitoring devices so we get a sense of how complex that grid is going to be on all these different pads?

[Winston Frederick Bott:]

Well, we're probably going to talk more about that next quarter and the quarter after, after we have some results, but Jack, can you answer that in a general sense?

[Jack H. Stark:]

Yes. I think you might be asking how often or how regularly we're going to be using this, because you're talking about -- but we've got other plans in mind, but I can speak specifically right now to the Hawkinson, if you'd like to do that?

[Andrew Coleman:]

Yes, please?

[Jack H. Stark:]

Sure. In the Hawkinson, we went in here and we had -- we're drilling 11 wells, and 4 of those wells were actually microseismic monitoring horizontal wellbores that ultimately we will be completing as producers. And we had one in the Middle Bakken, one in TF2 and 2 of them in the TF3. And the idea here was that -- and we've done this, and are doing this right now, we would monitor the fracture stimulation of a well from 3 vantage points. We had 3 wellbores that were being microseismically -- that were 3 microseismic monitoring wellbores active at one time. And by doing so, we end with just an exceptional database that allows us to really triangulate and properly place the fractures that are propagated from these fracture stimulation treatments. And so we've done that and, I mean, this is a -- I mean, as we mentioned before, this is probably the largest microseismic project that's going on worldwide. And I mean, we've had folks all over the world involved with trying to design and get this in place. And so we're setting a lot of records as far as what's being done here mechanically, but bottom line is that we could have upwards of 300 stimulations monitored in this basically 1280 unit. And so, we're going to get a lot of data here, and that is in turn going to allow us to -- as Rick has said, what we're trying to do here is we're really trying to determine what is the optimum well pattern, what's the optimum well density and what's the optimal way to develop the basically the container of oil that's here. When you think about it, we initially thought the oil container was Middle Bakken and Three Forks 1 only. Now we recognize it's Three Forks 2, 3 and 4 and so the container is bigger and we're trying to find the most efficient way to get the maximum amount of oil out of these units.

[Andrew Coleman:]

Okay, great. And then as you think about getting these wells, and once they all start producing, have you thought about 4D as a possibility or could you extend the life on those microseismic to kind of accomplish the same sort of thing?

[Jack H. Stark:]

These microseismic wellbores are being converted to producers and so we won't be doing any more monitoring right here, but that's down the road maybe.

[Andrew Coleman:]

Okay. All right. And then I guess, how much of the potential, I guess, new information from all these testing is factored in or it's to the risk numbers that you all talked about in your Analyst Meeting last year?

[Harold G. Hamm:]

Not sure we understood your question, Andrew.

[Andrew Coleman:]

Well, you all had given a total well count for the Bakken and Three Forks locations, I guess, how conservative, I guess, were the risking factors used on those well counts I guess last year? And -- or should we just wait until closer to year-end and start of next year to kind of get a refresh on what some of those numbers could look like?

[Jack H. Stark:]

Yes, we're working at refreshing it as we speak here. I've got some additional information here from wells that have been drilled, and so we continually are looking at that. So as far as risking, we essentially -- the risking that was done was just what percentage of the acreage we thought was respective at the time.

[Operator:]

Our next question will come from the line of Matt Portillo with Tudor Pickering and Holt.

[Matthew Portillo:]

Just one quick question for me. In terms of the Three Forks wells you've drilled, I was hoping to just get a little bit of color on how you think about the productivity and the EURs versus the Middle Bakken and kind of on average in the play?

[Richard E. Muncrief:]

Yes. Matt, this is a Rick Muncrief. What we mentioned earlier is we've had a nice range. If you look at our 603 model, we've actually overlaid the actual performance of our lower benches from the -- primarily, the TF2s and TF3s thus far. And what we've seen is really a nice bit, it does bracket. We've got wells that are well above that 603 model and we've got some that are below it. But when you put it in a graphical representation, it gives you a fairly high level of confidence that on average, that 603 is a pretty good number.

[Matthew Portillo:]

Well, I guess just asking it a different way. If I just completely separated the Three Forks versus the Middle Bakken, could you just give us a little bit of color on how you think about the relative economics of those 2 plays and maybe where they stack up in terms of the productivity on a Three Forks well on average versus the productivity of a Middle Bakken well on average? Is there a big difference or do you guys see that pretty similar? Just trying to get a picture on that.

[Richard E. Muncrief:]

Yes, there's really no difference. I mean, we've got areas where clearly the Middle Bakken are stronger than nearby Three Forks and we've got -- the inverse is also true. We've got some much stronger Three Forks wells than the Middle Bakken. So we really don't see an aggregate of significant difference.

[Matthew Portillo:]

And then just lastly, in terms of the SCOOP play, as you guys delineate this acreage position, was hoping to get a little bit of a better picture on maybe how you think about kind of the acceleration case here. And with that acreage delineation you have at the moment, how do you think about kind of the optimal rig count? Or is it a little too early to talk about that?

[Richard E. Muncrief:]

I think, we're going to -- we'll lay some of our plans out later in the fall when we talk about our 2014 budget. And our top priority #1 in SCOOP is we'll put together a very large acreage position. And similar to what we had to do a few years ago in the Bakken is our top priority will be to HBP that acreage.

[Operator:]

And our final question will come from the line of Ryan Oatman with SunTrust.

[Ryan Oatman:]

Wanted to talk a little bit more about these SCOOP wells, the initial rates were up, pretty good quarter-over-quarter. Normalizing, kind of excluding the extended reach lateral, can you talk about what you're doing there, then what you're seeing from a 30-, 60-, 90-day rates on these wells? I understand some others in the play are seeing these wells pretty flat over initial production periods?

[Richard E. Muncrief:]

Yes, Ryan, this is Rick Muncrief. I do agree with some of the early assessments. We do have variability, but by and large, we're very pleased with the 30-, 60-, 90- and 120-day rates on these wells. We've had some actually, where the 90-day rate is in essence flat to the 30-day rate. And so you're not seeing tremendous amount of decline. There's some reasons for that. Sometimes that may be infrastructure related, sometimes it's just the fact that you've got -- these are great wells. And so but we're real pleased with what we're seeing thus far and look forward to sharing more in the future.

[Operator:]

Ladies and gentlemen, this concludes our question-and-answer portion for today's call. I would now like to turn it over to Mr. Kilgallon.

[John Kilgallon:]

Thank you, Lacey, and thank you all for joining the call this morning. We did run a bit long today, but we didn't see others that had calls behind us so we appreciate you staying with us and we appreciate all the great questions. If you have additional follow up, please reach out to Warren and I. Thank you for this morning, and this concludes our call.

[Operator:]

Thank you, for your participation in today's conference. This concludes the presentation, you may all disconnect. Good day, everyone.