Continental Resources, Inc.
Q3 2015 Earnings Call Transcript

Published: 6 Nov 2015

[Operator:]

Good day, ladies and gentlemen, and welcome to the Continental Resources Incorporated Third Quarter 2015 Earnings Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Warren Henry, Vice President of Investor Relations & Research. Sir, you may begin.

[J. Warren Henry:]

Thank you, Amanda. I'd like to welcome everyone to today's call. Joining us today with prepared remarks are Harold Hamm, Chairman and Chief Executive Officer; Jack Stark, President and Chief Operating Officer; and John Hart, Senior Vice President, Chief Financial Officer and Treasurer. Also on the call this morning and available for Q&A will be Jeff Hume, Vice Chairman of Strategic Initiatives; Glen Brown, Senior Vice President, Exploration; Gary Gould, Senior Vice President of Operations; and Steve Owen, Senior Vice President of Land. Our call today will contain forward-looking statements that address projections, assumptions and guidance. Actual results may differ materially 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 addition, Continental does not undertake any obligation in the future to update our forward-looking statements made on this call. Also on the call, we will refer to certain non-GAAP financial measures, for a reconciliation of non-GAAP measures to generally accepted accounting principles, please refer to the updated third quarter presentation that was posted on our website at www.clr.com yesterday evening. To begin this morning, I'll turn the call over to Mr. Hamm for his comments on the third quarter and our current outlook. Harold?

[Harold G. Hamm:]

Thank you, Warren, and good morning, everyone. Thank you for joining us on the call today. We appreciate your investment in Continental Resources. On our last earnings call in August, we said our goal for the third quarter 2015 considering this challenging commodity price environment were to continue delivering outstanding production results, to continue lowering operating costs and to keep striving to balance cash flow with capital expenditures. Three months ago, we also announced strong initial production from our first test well and our STACK leasehold, the Ludwig well and told you of our plans to delineate further our position in the STACK play. While the third quarter is in the books and we delivered across the board, production came in solid at 228,000 Boe per day. Due to another quarter of strong production, we are once again raising year-over-year production growth guidance to a range of 24% to 26%. Let me take this opportunity to point out to you, we have now increased our production guidance 30% to 50% from original guidance set last year. While at the same time, we're projecting to be 8% to 10% under on CapEx, that's pretty impressive. Operating cost per Boe of production continued to decline from $4.39 per Boe in the second quarter to $4 per Boe in the third quarter. Just yesterday, we announced yet another positive revision in our operating cost guidance for the year. Lower production expense as well as lower G&A cost per Boe. Finally, during the quarter, we reiterated our commitment to balance capital expenditures with cash flow. John will provide more detail momentarily, but today we're approximately cash flow neutral at of $50 WTI and are making additional adjustments going forward to achieve cash flow neutrality as commodity prices continue to fluctuate. The key takeaway is this. Coming into this price downturn, Continental was lean in terms of personnel and operating expenditures, which has really paid off for us. Take your pick in terms of per employee revenue, production, market cap or other key performance metrics, Continental has always been a lean, focused organization and we're now taking advantage of the challenging environment as we preserve the continuity of our core teams and raised the performance bar to yet another level. We were also very quick to make adjustments in this commodity environment. We keep improving and getting more efficient, drilling and completing wells in fewer days that reduce costs. We are very well-positioned to preserve the value of our assets, if a low commodity price environment persists, as well as preserve the growth and potential of our premier asset portfolio. We continue to deliver on the exploration side. Jack will describe our recent success in greater detail. And let me just say that STACK has emerged as yet another high-value growth opportunity for Continental. We currently own 146,300 net acres and Continental's well completion results, as well as those of industry peers, continue to validate our high expectation for the over-pressured window in the STACK play in Blaine, Dewey and Custer counties and this over-pressured window is definitely a step change in the STACK play. Finally, from a more global point of view, I'd like to comment on U.S. crude oil exports. We continue to see movement toward lifting the 1970s Nixon-era ban, which has never served U.S. national interest and is even more detrimental to everyone today. We have bipartisan support for a reasonable solution lifting the ban and look forward achieving this before year-end. America's energy industry is as competitive as it's ever been and now we're preparing to compete freely once again in a global energy market. Get ready for American leadership to show just what it can do. With that, I'll turn the call over to Jack.

[Jack H. Stark:]

Thanks, Harold, and good morning, everyone. I appreciate you joining us on the call today. To start off, I wanted echo Harold's comments and thank all of our employees for their dedication, ingenuity and successful efforts in the third quarter. They really stepped up and once again did an outstanding job curtailing cost, increasing efficiencies and maximizing the return on every dollar spent. The improved guidance we announced yesterday for 2015 reflects their achievements. Today, I want to focus on two things. First, an update on STACK and then I will touch on the cost saving operational efficiencies that we continue to achieve throughout the company. Our STACK acreage in Oklahoma has quickly evolved into another high quality asset that is completely incremental to Continental and its shareholders. The company has no reserves on the books for the Meramec and the STACK reservoirs, underlining our 146,300 net acres and our production in the play has just begun to grow. Since announcing our first STACK completion last quarter, we have completed two more wells and are in the process of drilling or completing four more. In addition, we have conducted intense geologic and reservoir studies including industry-wide result to better understand the play. What we have concluded so far, the STACK is an exceptional value-added opportunity for Continental shareholders. Here are five key takeaways that we can provide from the data we have at this time. First, based on our current geologic and reservoir studies, we're comfortable saying that the net unrisked resource potential for our STACK acreage exceeds our expectations for SCOOP Springer and could approach that of our SCOOP Woodford based on reservoir thickness, over pressuring and early well performance. Second, from an economic standpoint, our STACK acreage looks like it will compete head-to-head with our economics in SCOOP. We'll provide more clarity on STACK economics in the coming months as we build our reserve models. Third, more than 95% of Continental's acreage is located in the STACK over-pressured window or bottom hole pressures reach up to 0.8 PSR per foot, almost twice normal bottom hole pressure. Our reservoir study show that wells completed in the over pressure window had 90-day rates three times higher than the wells completed in the normally pressured window. This includes 48 wells with 90 days of reported production normalized to a 9,800 foot lateral length. From experience, higher 90-day rates typically translate to higher EURs in tight resource plays like STACK. We'll provide more clarity on EURs when sufficient production histories are available. Fourth, our acreage is concentrated in some of the thickest liquids rich portions of the play, based on our current geologic model. The STACK petroleum system ranges from 700 feet thick to 1,200 feet thick under our acreage in Blaine, Dewey and Custer counties, which by comparison averages around 600 feet thick in the Kingfisher and Canadian County areas. We currently estimate that 30% of our acreage lies in the over pressured oil window, 60% in the over pressured condensate window and 10% in the over pressured gas window. And finally, last point, approximately 60% of our 146,300 net acres is already held by productions. So the majority of our acreage is already secured. So, needless to say, we're quite optimistic about our STACK acreage. Wall Street analysts have justifiably credited significant net asset value to several of our peers based on the results of their activities in Kingfisher and Canadian counties. Likewise, Continental should see significant increases in net asset values. We continue to demonstrate repeatable results in our Blaine, Dewey and Custer County acreage over the next year and beyond. To date, Continental has completed three Meramec wells and we're very impressed with the early results. Our first well, the Ludwig 1-22-15XH, was reported last quarter flowing 2,076 barrels of oil equivalent per day at 2,100 PSI, flowing casing pressure and 76% oil. Afterwards, the well continued to clean up and eventually peaked at 2,782 barrels of oil equivalent per day. As announced yesterday, we completed two additional Meramec wells during the third quarter, the Ladd 1-8-5XH and the Marks 1-9-4XH. The Ladd well located 3 miles northwest of Ludwig completed flowing 2,181 barrels of oil equivalent per day at 2,000 pounds flowing casing pressure and 79% oil. The Marks well located 2 miles northwest of the Ludwig flowed at 994 barrels of oil equivalent per day at 625 PSI, flowing casing pressure with 73% oil. All three of these wells were extended laterals, ranging from 7,800 feet to 10,100 feet in length. Our targeted completed well cost is $9.4 million per well, reflecting the cost of 2 mile laterals in the deeper over pressured window. We expect these costs will be more justified – more than justified by the superior performance of the wells in these areas. Our focus going forward is to continue delineating and de-risking our acreage, monitor production and further develop our acreage in economic models. We currently have three operated rigs drilling in the play and plan to maintain roughly that level of activity as we continue to de-risk and delineate our acreage. Our efforts will be augmented by industry drilling – STACK is one of the few plays in U.S. where the rig count has actually increased this year. There are currently 25 rigs targeting the STACK, Meramec and Osage reservoirs and approximately half of them are located in the over pressured window. Before moving on, let me point out the STACK is an example of the type of asset that gives Continental a lot of optionality, and how we proceed with development. Accordingly, STACK is one of several assets where we may consider strategic alternatives such as a joint venture to accelerate value or reduce debt. Now, at this point, I'd like to turn the spotlight on our operating teams and how they've driven down cost and continue to develop new cost savings that will pay dividends for years to come. Their achievements this year have been remarkable and in the third quarter, they continued to reset the bar with today's drilling and completion technologies. Our Bakken drilling team has been committed to decreasing the spud to TD drilling times throughout the year. And in the third quarter, they achieved an average reduction of 15% in days spent drilling compared to the average for the first quarter. The average day spud-to-TD during the first quarter was 17.6 days and 16.6 days in the second quarter. During the third quarter, it was an impressive 15 days and they tell me they're not done yet. Some of the biggest strides are being made in the days – in the lateral. During the quarter, we set a new Continental record by drilling a 9,490 foot lateral in a remarkable 2.4 days. Not to be outdone, our Bakken completions team has taken a new approach to drilling out plugs that has reduced average drilling – average drill out times by 50%, saving approximately $300,000 per well. Overall, our enhanced Bakken completion well costs are down 27% year-to-date to $7 million per well, thanks to the drilling and completion teams' ingenuity and service cost reductions. During the quarter, our SCOOP drilling team demonstrated that significant potential lies ahead with the increased drilling efficiencies in SCOOP as the play matures. Knowledge gained from drilling the nearby Poteet, Honeycutt density pilots enabled them to drill the Vanarkel density pilot wells in almost half the time on a per well basis. This reduced the average drilling cost per well by 45%. We are seeing drilling efficiency gains of various scales throughout SCOOP, and expect to see these efficiencies translate more and more to the bottom line as the play matures. Year-to-date, our estimated average cost of a 7,500 foot lateral in the Woodford condensate window is down 21% to $9.6 million per well. We're excited not only by our gains in operational efficiencies this quarter, but also our continued strong results from enhanced completions. In Williams and McKenzie County area of Bakken, we currently have 98 operated wells in our enhanced completion dataset from 90 days or more of production. Results show an uplift of 34% to 48% in 90-day production rates, and an impressive 30% to 45% increase in early EUR estimates. We're also applying enhanced completion designs in the SCOOP and STACK areas testing higher proppant loads and more stages and seeing very encouraging results. We'll communicate results from these tests in future quarters as we compile more substantial dataset of enhanced completions in the Southern region. So I'll close by saying we're very pleased with the operational efficiency gains made this year and the prospects of more to come. In the end, these gains stick with us for the long haul and increase the value of our assets, which in turn translates to more value to our shareholders. With that, I'll turn it over to John to discuss updated guidance and the financial results.

[John D. Hart:]

Thank you, Jack. Good morning, everyone. Revenue for third quarter was $683 million and EBITDAX was $472 million, both reflecting the continued weakness in commodity prices. Continental reported a net loss of $82 million or $0.22 per share for the third quarter of 2015. Adjusted to exclude impairments, non-cash gains and losses on derivatives and gains and losses on asset sales, the net loss was $44 million or negative $0.12 per diluted share. Offsetting some of the weakness in commodity prices were healthy production growth and reduced operating expenses per Boe in the quarter. Production averaged just over 228,000 Boe per day in the third quarter, declining sequentially in August and September. The decline trend reflects our lower pace of activity and significant reduction in well completion activities, especially in the Bakken. As noted in our press release, we expect to exit December with production of approximately 210,000 Boe per day. The exit rate is an estimate and could vary based on the timing of various completions, particularly those associated with large pad projects. In looking at the composition of our production, we know we exceeded Street consensus for oil production, gas production and total production, individually and in the aggregate. Oil production was 65% of total production, down from historical norms due to our deferral of Bakken completions and greater capital focus in SCOOP and STACK, where we are delineating our positions. Although, this increases our gas composition in the short-term, we note this rate ratio can reverse quickly as oil prices recover and we dedicate more capital to the Bakken in the Springer shale. For fourth quarter, we expect the oil ratio to be 64% to 65%. Capital expenditures for the third quarter were $540 million. We expect fourth quarter CapEx to be between $350 million and $400 million, leaving us $200 million to $250 million under our $2.7 billion CapEx budget for the full year. Changes from our previous estimates reflect some additional completions in the South and higher CapEx projections associated with outside operated well completions. As Harold noted, we are delivering stronger production for less CapEx. Operating cost performance continues to be very strong, production expense dropped to $4 per Boe in the third quarter, down from $4.39 in the second quarter this year. This reflects diligent cost management coupled with strong production results. G&A, apart from equity compensation, increased sequentially to $1.95 per Boe, but was still solidly within our guidance range. Non-cash equity compensation dropped to $0.61 per Boe in production, down from $0.77 in the second quarter. Earlier, Harold referenced the lean focused nature of our organization. Our G&A reflects his comments as we're among industry leaders, not only in G&A per Boe, but also efficiency per employee such as production per employee and revenue per employee. Total cash costs including interest was lower at $12 per Boe in the third quarter, which was a reduction of 3.5% from Q2. Our cash cost are also among industry leaders and a strong testament to see a large efficiency. As we noted, third quarter oil differentials continued to trend lower to $7.54 per barrel versus $8.18 in the second quarter. Approximately, 75% of our Bakken production is now delivered to market via pipeline. As noted in prior quarters, we believe improvement in oil differentials will continue. And although quarter-to-quarter may show volatility, the long-term trend is expected to be improved. The third quarter gas differential was $0.54 per Mcf, $0.04 below the lower end of our full year guidance. However, for full year to 2015, we expect to be within our guidance. Given continued improvements in performance through the third quarter, we have once again revised full year 2015 guidance to reflect these positive metrics. Note these revisions that we announced last night are on top of the positive revisions we made in the second quarter. Let me review those. First, we now expect to increase production by 24% to 26% for 2015, up from the prior guidance of 19% to 23%. Secondly, we're looking for production expense of $4 to $4.50 per Boe, down from the prior range of $4.75 to $5.25 per Boe. G&A guidance is now in the range of $1.70 to $2 per Boe, compared with the previous range of $1.75 to $2.25 per Boe. Non-cash equity compensation improved to a range of $0.65 to $0.75 per Boe, down from the prior range of $0.70 to $0.80 per Boe. Production tax is now in a range of 7.5% to 8% compared with the previous range of 7.5% to 8.5%. And finally, oil differentials are now in a range of $7 to $9 per Boe, tightened from the prior range of $7 per Boe to $10 per Boe. Complete updated 2015 guidance is available on our investor presentation, posted on the website and in yesterday's earnings release. On the financial side, we continue to have ample liquidity and no near-term debt maturities. At the end of September, we had $17 million of cash and cash equivalents on hand. At this point, I would like to provide additional color on our credit facility. There's a lot going on with various energy credits, so we thought it made sense to reemphasize a few key points related to Continental. Continental's facility is unsecured and not subject to any borrowing base redetermination. Additionally, there are no terms within our facility that would allow for or mandate collateral or a borrowing base calculation to come back into place. Therefore, we are not and will not be subject to any borrowing base redetermination. Our only covenant is a debt to total capital ratio. Capital includes debt of no greater than 0.65. At September 30, we were at 0.57. When calculating this covenant, it is important to note that the calculation, according to the terms of credit agreement, specifically excludes any non-cash impairments after June 30, 2014. Obviously, we have ample room under this covenant. At November 4, 2015, we had $880 million drawn on our credit facility. We remain committed to focusing on cash flow neutrality and limiting incremental debt. Consistent with our focus on reducing cost, yesterday we completed two transactions that enhanced liquidity and lower annual interest expense. First, we have increased the commitments under our credit facility by approximately $250 million, which brings total commitments to $2.75 billion. This will provide incremental liquidity further facilitating our ability to call $200 million of our 7.375% bonds currently due in 2020. While we have not made a formal decision for calling these bonds, we note that calling and financing on our revolver at current rates would reduce the associated interest expense by approximately 5.5%, saving in excess of $11 million of annual interest expense. Additionally, we entered into an unsecured three-year term loan with banks in our credit facility at a current interest rate of LIBOR plus 137.5 basis points or 0.125% less than our current revolving credit facility, saving $2 million in interest over the three-year term. After these transactions, availability under our credit facility is almost $1.9 billion. Our facility allows for commitments up to $4 billion, but we have not accessed the full allowable level as we do not need to and do not want to incur additional commitment fees. We note that bank response for our two transactions was very strong, with our offering being significantly oversubscribed. We had strong receptivity by existing banks and have added two new financial institutions. The strategic implication of these transactions is keeping our balance sheet strong, reducing interest cost and demonstrating that we have ready access to additional liquidity if it were needed. Don't confuse this with any intention to add debt. That is not our plan. We remain committed to maintaining our investment-grade rating and believe we have the financial flexibility to do so. We plan to announce full 2016 guidance in late December or early January. In today's commodity environment, our focus is on cash flow neutrality or said differently no new debt. Doing so preserves our financial flexibility and assets for a better commodity environment. We expect our 2016 guidance will reflect this view and reflect relatively flat or slightly lower production compared to the 2015 exit rate guidance. For example, 2016 capital at $1.5 billion to $1.6 billion is estimated to hold 2016 production flat at 200,000 Boe per day. At current commodity prices, this level equates to cash flow neutrality. The commodity markets are evidencing continued volatility. We remain willing and able to adapt to short-term fluctuations while viewing the long-term favorably. With that, we're ready to begin the Q&A session. And I'll turn the call back over to the operator.

[Operator:]

Thank you. Our first question comes from Drew Venker of Morgan Stanley. Your line is open.

[Drew E. Venker:]

Hi. Good afternoon, everyone. I was hoping you could just speak a little bit more on the Meramec. Can you talk about the variability in those first few tests, two of those look very consistent in terms of rate and pressure. There is notably lower rate and pressure despite being in a close proximity. Can you give us a sense of how much you think that is related to geologic variability and how much related to differences in completion?

[Glen A. Brown:]

This is Glen Brown, I'll address that. The difference really is the geo-steering issue. We tried a different pattern and we drilled the well in a down dip pattern going across the formation. The other two wells are drilled from hill going up. And so basically, it's targeting, targeting is very important in all our plays and we're very early in this play, but we expect our targeting to improve and the wells to be persistent, especially as we go to the deeper depths with higher pressures.

[Drew E. Venker:]

Okay. And as far as the program throughout 2016, you mentioned planning to delineate your acreage, how far do you plan to step out from your first few tests?

[Glen A. Brown:]

We've already stepped out. We've landed casing and smattered in on our Bowden well, which is approximately 30 miles to the Southwest of testing. What we still think is in our oil fairways and we're going to be completing that starting next week. We also have a Compton well, which is in halfway between the Bowden and the Ludwig wells and several other wells that are drilling. This is also added to by other industry wells that we are participating in or have working interest in. So, it's very active.

[Drew E. Venker:]

Okay. And lastly just on the longer term well performance, pressures look very high. Is that consistent with relatively flat decline rates, or can you speak to how the first couple wells have held up?

[Jack H. Stark:]

The wells are holding up very well – excuse me. The key there with those high pressures is that we are in over pressured area. And so this over pressured area has given us three times the rates when you normalize per foot of lateral and that's why the economics here is going to be much stronger than the Eastern part of the play.

[Drew E. Venker:]

It's okay.

[Glen A. Brown:]

I might add to that. We have a working depth range for our properties between 10,000 feet and 16,000 feet.

[Drew E. Venker:]

Thanks.

[Glen A. Brown:]

Thanks.

[Operator:]

Thank you. Our next question comes from Leo Mariani of RBC. Your line is open.

[Leo Mariani:]

Hi, guys. I was just looking for some clarity around the comment that you all made regarding 2016 were basically kind of keeping production at roughly 200,000 barrels a day at that maintenance level. Is that the $50 WTI price that you all cited, is that a strip, just wanted to get some context around price?

[John D. Hart:]

Yeah. The cash flow neutrality comment is at 50% or slightly under. It's really in line with where we're at today. So, we're kind of in the 47%-ish range. So, certainly at 50%, but I think we would have a little bit more cash flow at that level.

[Leo Mariani:]

Okay, that's helpful. And obviously it sounds like you guys have considerably slowed down completions here particularly in the Bakken in the short-term. Just trying to get a sense of when do we think the frac crews come back, is that early next year or are you guys just kind of closely watching oil prices in order to make that decision, any color you have there would be helpful.

[Harold G. Hamm:]

Certainly, it depends on price, Leo, and also cash flow neutrality. So that's a determining factor.

[John D. Hart:]

Yes. The model that we gave you there's lot of flexibility in that. We did it in a way what we drilled next year, we would complete next year, but obviously that could be a few months in or we could accelerate that by working down debts if we choose to. So there continues to be some optionality and flexibility in some of those numbers and how we approach next year.

[Leo Mariani:]

Okay. That's helpful for sure. And I guess in terms of the STACK, I couldn't help notice you picked up some extra acreage this quarter. Do you guys continue to take those opportunities to build that position?

[Steven K. Owen:]

Yes. This is Steve Owen. There's always opportunity out there. It's highly competitive, just like all of our other assets, everybody wants in the play, but we keep hitting hard and we'll keep succeeding.

[Leo Mariani:]

All right. Thanks, Guys.

[Steven K. Owen:]

Thank you.

[Operator:]

Thank you. Our next question comes from Jason Wangler of Wunderlich. Your line is open.

[Jason A. Wangler:]

Hey. Good morning. Just maybe dovetailing a bit on the previous question there about the Williston and the completions, given the backlog, it's going to be in that 115 range here at year-end. If we go through the year-end, prices kind of stay here. Is there a level that you're looking at, saying okay, that's a selectable ore, that's enough and we can go deploy capital down in Oklahoma or is it just simply, we'll keep drilling up there with the eight rigs?

[Harold G. Hamm:]

We certainly will not. If price doesn't recover, we're not going to continue at the eight rig level. We have flexibility. If it does, we can keep those rigs but we won't continue if price doesn't recover.

[Jason A. Wangler:]

Okay. And maybe just down in Oklahoma, how you see the rig allocations playing out, not trying to necessarily nail down a number for next year. But more, I guess, a percentage or something between the, call it, three plays. Where do you see the activity going from now until next year?

[Jack H. Stark:]

Well, this is Jack. And I think that you'll see the rig allocation kind of stay where it's at right now. We've got three wells in STACK; we've got five wells in our Northwest Cana and seven wells down in SCOOP and we have the ability to fluctuate back and forth between the plays, but I think it's a fair statement to say it's what you could expect going forward.

[Jason A. Wangler:]

I appreciate it. Thank you.

[Operator:]

Thank you. Our next question comes from Brian Singer of Goldman Sachs. Your line is open.

[Brian A. Singer:]

Thank you. Good morning.

[Jack H. Stark:]

Morning, Brian.

[Brian A. Singer:]

You mentioned in your comments as it relates to STACK that you would consider a joint venture or – and I think you said potentially consider a divestiture or other monetization. Can you talk about your goals in considering this? Is there a leverage ratio you're looking to achieve that can be aided by material asset sales or do you see just more synergies based on the competitive landscape if STACK were jointly developed or developed by others?

[Harold G. Hamm:]

Really as mentioned in here, this is just an asset, STACK is that that we sure could consider some options with, but we're an opportunistic company. We like to keep our options open and bottom line, if there's value that we can create by doing some arrangement like that, bring value forward for the shareholders, we'd be surely considering doing that.

[Brian A. Singer:]

Got it. Thanks. And then sticking a little bit with the capital allocation theme. Cash flow neutrality, it's not necessarily the company's history over the last few years, but certainly understandable in the environment that we're in now. Do you see staying within cash flow as a cyclical objective or a secular objective and particularly as it relates to the MidCon and the Southern region, can you talk about the role natural gas prices play in influencing your capital allocation?

[Harold G. Hamm:]

Well, I don't think anybody (35

[Brian A. Singer:]

Great. Thanks. And how does natural gas prices influence your decision making and particularly in the Southern region? Is it relevant? I know you had some good rate of return charts in one of your slides. But do these gas prices make sense if you didn't have HBP?

[Harold G. Hamm:]

Well, we look at everything with the rates of return. And certainly, these plays, they're great plays and provide a good rate of return and we walked on every one. Gas prices do impact those plays and as does oil prices. So, yeah, we pay attention to them, close attention.

[Jack H. Stark:]

I was just going to say, we still see that we're getting decent rates of return even down in that $2 range and we've driven down cost to $9.6 down in the SCOOP area and we continue to see efficiency build and specifically some of them that we noted we saw drill times cut in half when we started to go into density drilling and development drilling. So there's a lot of basically cost reductions still that lie ahead of us there in SCOOP and we're really – as you can see by some of the things we've said, we started to already realize those and those are really going to play a factor in the economics and really our decision to continue to drill down there.

[John D. Hart:]

Brian, it's also very – we're not – these aren't dry gas plays we're in, it's a very rich gas. So as you see a recovery in the oil price, you're going to see the overall realization go up not only on the oil, but the various NGLs that we've got in there. So, it's a long-term play that is still very economical today, but has a great multiplier on it going forward with the commodity coming back up some on the oil side.

[Brian A. Singer:]

Great. Thank you.

[Operator:]

Thank you. Our next question comes from Doug Leggate of Bank of America Merrill Lynch. Your line is open.

[Doug Leggate:]

Thanks. Good morning, everybody.

[John D. Hart:]

Hi, Doug.

[Doug Leggate:]

John, just to answer the breakeven question a different way, you previously talked about maintenance capital number. I think it dropped to $1.8 billion to $2 billion. Where would you say that is now to whole production flat of the exit rate for 2015? (38

[John D. Hart:]

Yeah. If you look to last quarter, we indicated that the maintenance capital was $1.6 billion to $1.8 billion and that that would hold production flat at 200,000 to 215,000 a day. So here, we've updated to say that $1.5 billion to $1.6 billion will hold us flat at 200,000 a day. So, you see that's improved a bit. So, you know, costs have continued to come down and Jack gave a few of the examples of the efficiencies that we're garnering earlier, but it's a long list. So, you know it's tighter by $100 million on both end of that range. So, $1.5 billion to $1.6 billion will hold us flat at 200,000, somewhere around $1.7 billion would give you 215,000 to 210,000 type number.

[Doug Leggate:]

Got it. Thank you for that. Jack, my follow-up – I've got two actually if I may. First of all, on the Newy well, it seems that you obviously had some fairly substantial reductions in drilling times. My understanding is that you've taken a little bit more of an integrated service approach there sort of playing some of the service companies up against one another. I'm wondering if you could give us some idea as to whether you think those rates might be repeatable. And if so, what the implications are for the well costs in the SCOOP. And I've got one final one, please.

[Jack H. Stark:]

Sure, Doug, I'll let Gary handle that.

[Gary E. Gould:]

Yes, we are very pleased with what we're seeing. We're testing that out with several different service companies. And what that's allowed us to do is just have better communication among the service companies who are working for us. It's also allowed our service companies to be in the same mode of frame we are as far as keeping costs down as we bundle different services with them. It's allowed us to test some new technology. And then, as far as overall cost, we expect that bundling should save us about $400,000 per well or more going forward. But that's still not built into our current estimates, because we're still testing that out.

[Doug Leggate:]

So the $9.6 million on the slide, the 7,500 foot lateral, that does not reflect any of those efficiencies?

[Gary E. Gould:]

That's correct, because those are – those efficiencies were still in the early stages of testing.

[Doug Leggate:]

Got it. Thank you. And my final one, Jack, maybe this one is for you. But obviously, there's a fairly seems like kind of an unclear transition zone in the STACK between the really high gas areas and the oily areas. So I'm just wondering if you could give us some confidence level about where your acreage is if you feel that it's shallow enough, as you see, as continuing with those kind of oil cuts that you've seen.

[Jack H. Stark:]

Well, Glen, you could maybe step in here. But I'll just say that what we see here right now is that 30% of our acreage, as we mentioned, is in the, what we consider, the volatile oil, our over pressured oil window, and about 60% is in the liquids-rich condensate window. And to our surprise, we're seeing that oil window expand going West based on results. And so, I think we towed 25% of our acreage, last time it was in the oil window and now we're seeing it's 30% and we have expectations that could grow from there at this point. And so in the end, still evolving, Doug, but believe me, with the numbers we're giving you here are literally based on well results that we have right now.

[Glen A. Brown:]

That's right.

[Jack H. Stark:]

Anything else, Glen?

[Glen A. Brown:]

Well, there is some information that we can't release at this point that gives us a suggestion in the direction that Jack's indicated, other people as well.

[Jack H. Stark:]

Right.

[Doug Leggate:]

All right, guys, I'll leave it there. Thanks so much.

[Jack H. Stark:]

Thank you.

[Operator:]

Thank you. Our next question comes from Brian Corales of Howard Weil. Your line is open.

[Brian Corales:]

Good morning, guys.

[Harold G. Hamm:]

Good morning, Brian.

[Jack H. Stark:]

Good morning, Brian.

[Brian Corales:]

Looking at the Bakken and the 123 well backlog, are some of those wells completed just not brought on production?

[Gary E. Gould:]

That's correct. About in the range of 20 wells to 25 wells have been completed and not yet on production. We expect those to be put on production this quarter.

[Brian Corales:]

Is that just based on oil prices or is this something that is wider spread in the Bakken right now?

[Gary E. Gould:]

This is just based on pad timing and just the timing, getting facilities ready to put them back on.

[John D. Hart:]

We probably weren't as fast in moving on them when oil prices dipped back down, but you're seeing them come back on this quarter. That's part of the reason you're going to see that the oil percentage remain relatively constant in the fourth quarter, even though we're not completing incremental wells, if you will.

[Brian Corales:]

Okay. Now, that makes sense. And John, maybe a question for you. I felt that was a great move getting kind of – I don't know if you call them term notes, but is that – I haven't seen that before. Is that something that could be upsized and it sounds like it's just through your banks, the $500 million term loan?

[John D. Hart:]

I think we can do larger if we chose to on that. We did it with our existing banks and then like I indicated, we added a couple of additional institutions. With that group, we were a couple of hundred million or more over subscribed, so we could have grown it there. And frankly, we had several banks reaching out to this that would like to enter into our facilities. So, there is optionality, it's very unique and creative times and what we're focused on are lowering our cost and maintaining a strong liquidity.

[Brian Corales:]

Okay. And just one – thanks, and one final question. Jack, you talked about, considering potentially JV'ing or getting a partner for the STACK. Is that just for any of your assets you're willing to do that? Is something different about the STACK and say the Springer, can you maybe just elaborate there?

[Jack H. Stark:]

Well, I'd just say, it's like Northwest Cana. We brought in a JV partner there, it was an idle asset that we thought it made sense to bring in a partner, bring some of that value forward and we did that. And so, it isn't just STACK, we'd consider this another assets. But there is a – being that a lot of what's going on in the STACK is actually new and completely incremental to the company. I mean we have no reserves on the books, no production. It's an asset that's all easier to do that and then one that, it has a lot of history of drilling and a lot of existing production and what have you. So, it makes it – just tease it up a little bit better to do something like that.

[Brian Corales:]

That makes sense. Thanks, guys.

[Jack H. Stark:]

Thanks, Brian.

[Operator:]

Thank you. Our next question comes from the Noel Parks of Ladenburg Thalmann. Your line is open.

[Noel A. Parks:]

Good morning.

[Jack H. Stark:]

Good morning.

[Noel A. Parks:]

I was wondering, turning to the Springer for a second. Can we get an update on the land situation there, upon announcing the play you've had to go get some swallow rights on some of the acreage, I wonder if that process is pretty much done or still had ways to go?

[Steven K. Owen:]

This is Steve Owen, Noel. Yes, it's ongoing. Our core Springer right now is 211, our core overall is 258, we're actually higher than that at this point. Those are in the third quarter numbers. It's an evolving process and never stops for us.

[Noel A. Parks:]

Okay, great. And...

[Steven K. Owen:]

That does include over 10 acquisitions also in addition to pre-leasing, we're just – we're on the ground every day.

[Noel A. Parks:]

Great. And in the SCOOP, I think last quarter, you were talking a bit about having done some micro-seismic studies in the SCOOP, I just wondered if you have any results or insight from that?

[Jack H. Stark:]

Yes, we did a micro-seismic shoot in our May unit. We did it on two different wells and tested different types of completion techniques, and we got really good data, and we've used that to model our enhanced completions in the area going forward.

[Steven K. Owen:]

Yeah. In fact, that micro-seismic project was really beneficial, because we actually did some modifications on the fly as we were monitoring the micro-seismic events in our stimulation. So it's a very good project for us, because it gave us some really new perspectives and added perspectives that will pay dividends going forward.

[Noel A. Parks:]

Okay. And just what sort of modifications did you mean? Was it proppant loading or changing the pages going forward?

[Gary E. Gould:]

Yeah, this is Gary Gould. Some of the enhanced completions that we're looking at in the South on the SCOOP and STACK properties are associated with shorter stage lengths, but especially profit loading, that's really the biggest change. We're seeing a lot better rates, which we (47

[Noel A. Parks:]

Great. And my last one, John had mentioned regarding CapEx for the quarter, something about non-operated completion activity was – what was included. Was that in the particular region Bakken, SCOOP?

[John D. Hart:]

All right, it was spread across the company we saw a higher level of non-op activity in the cost come in than what we had modeled in September.

[Noel A. Parks:]

Okay. And you think sort of a onetime or sort of a seasonal trend just as we're heading into winter in the Bakken or...

[John D. Hart:]

There are a variety of reasons with timing. Some of it's probably you saw a little bit of a spike in the late summer in oil prices. And they provide in a little more and Bakken off now would be my expectation. But we've modeled that actively and we closely follow, but it is – it can be a variable at times.

[Noel A. Parks:]

Thanks. That's all from me.

[John D. Hart:]

Thank you.

[Operator:]

Thank you. Our next question comes from Pearce Hammond of Simmons & Company. Your line is now open.

[Pearce Wheless Hammond:]

Good morning. For your year-end 2015 exit rate, what will be the production mix, will it be similar to the 64% to 65% you mentioned for Q4? And then as you look out on 2016, do you think your production mix will get gassier?

[John D. Hart:]

For the exit rate we will be close to that, probably closer to the top end of that to 65% more so, but that would be our expectation. For 2016, there is a lot of active modeling going on right now. So we'll guide you on that when we put out the 2016 guidance here in the couple of months. It really depends on the deployment of capital and the timing of completion activity back in the Bakken. That is something that I want to point out that we can easily reverse that percentage trend by just dedicating more money to the Bakken than we have in the last 9 months to 12 months.

[Pearce Wheless Hammond:]

Great.

[Jack H. Stark:]

I would just mentioned there that there is – I've heard there is discussion about the mix getting a little more gassy, and it's really just an allocation of capital thing. I mean our assets haven't changed. I mean the SCOOP and Bakken are still exactly where – that's just where we're choosing to put the dollars right now. And we're looking at HBP'ing acreage and there's just a lot of variables in here, but as far as the mix is concerned corporately, I mean our mix hasn't really changed.

[Pearce Wheless Hammond:]

And then at what oil price would you be willing to allocate some more capital to the Bakken and start moving that mix oil here?

[John D. Hart:]

It depends on where we see supply and demand going. I mean, when we see prices firm, feel a little stronger, we can get a little more aggressive on the oil side. But right now, we're comfortable with what we're doing right now, because we're HBP'ing acreage and we're expanding STACK. I mean that's a great thing and what we're producing in STACK is 73% to 79% oil. In fact, our Ludwig well, I think is flowing like 83% oil. So, we're working on some oily products or oily reservoirs right now.

[Jack H. Stark:]

Pearce, that's kind of a layered answer also in that we've got docks that we would work off, that's probably in a lower price than where we would put an incremental rig back into play. So there's a good mix and there's a lot of flexibility that we have and just part of the understanding and how quickly we can really reverse that when we choose to.

[Pearce Wheless Hammond:]

Great. One last one from me. What are your expectations for further service cost declines in 2016 versus 2015 on a percentage basis?

[Gary E. Gould:]

This is Gary Gould. Over the next several quarters, I would expect through a combination of vendor (51

[Pearce Wheless Hammond:]

Thank you very much.

[Operator:]

Thank you. Our next question comes from Marshall Carver of Heikkinen Energy Advisors. Your line is open.

[Marshall H. Carver:]

Yes, you're off to a very good start in the STACK and looks like most of your activity so far has been at Eastern Blaine County. When would you plan on testing the stuff over in Dewey or maybe in Custer counties, would you get to that in 2016?

[John D. Hart:]

Yes, I think we're – the play has been obviously developing from East to West, and so the play has been historically in the under pressured part of the play and we've now gone through a step function where we jumped into the Ludwig area, which is the over pressure and we'll – we see it as a real steady westerly flow of development. And so we will certainly get to our acreage positions to the West. But we're benefited there by our Northwest Cana JV where we're developing Woodford and HBP'ing acreage there is a benefit of that – that five rig program.

[Marshall H. Carver:]

Okay. Have you seen anything, I guess, you've drilled through the Meramec with your Northwest Cana wells. What have you seen to make you excited that the wells...

[John D. Hart:]

Well, that's, yeah...

[Marshall H. Carver:]

...to drill?

[John D. Hart:]

I'll take that one too. Every day – every week, we're pulling a log of our Meramec rights. We did not transfer Meramec, Osage rights within our Northwest Cana. We're seeing us go from 600 feet over in the Kingfisher area to depths of 700 to 1,200 total feet as we move to the West. And what we're seeing is just exceptional log sections and shows that we'll be providing to you in the future in much greater detail. Very encouraging results.

[Jack H. Stark:]

Yeah. He's being specific about the Meramec interval, and I'll just add too, that probably 30% of the wells we drill have got additional pay behind pipe that we've encountered on the way down. And that's in the Springer, the Manning, the Chester. So, we're really pleased with what we're seeing here. And really this is just – we're just starting to be able to come out and tell you some of the things we see going on in here and in the next few months, quarters. We're going to be able to bring a lot more information to the table here to show just what a terrific asset this looks like that we have.

[John D. Hart:]

Yeah. I would just add real briefly that we're talking about roughly twice the thickness of the pay as we move west, that's been developed to date by the others in the industry. And we're talking about up to twice the pressure. So those two additives are leading us in the right direction.

[Jack H. Stark:]

And the thing again I just got to repeat is, 60% of this is HBP'ed. And so we really don't have a backup against loss those big to try to get things HBP'ed. And then we can really strategically step out and develop our perspective of this play as we want. And so we're just in a very good situation here and I think there is a lot more good news to come from this play.

[Marshall H. Carver:]

All right. And one follow-up on the oil window versus the condensate window, is there a specific commodity mix, is it 75% oil and greater you're calling the oil window or how are you defining that?

[John D. Hart:]

We are defining the, what we call black oil to 1,800 gas oil ratio from 1,800 to 10,000 gas oil ratio, we're calling that our volatile oil and 10,000 to a 100,000 is our liquid-rich condensate. And obviously, above that is dry gas. That's how we analyze most of our plays.

[Marshall H. Carver:]

Okay. Thank you very much and congrats on the early results.

[John D. Hart:]

Thank you.

[Jack H. Stark:]

Thank you.

[Operator:]

Thank you. Our next question comes from Subash Chandra of Guggenheim Securities. Your line is open.

[Subash Chandra:]

Another question on STACK. Other than thickness and over pressure, how consistent are the rock characteristics from east to west?

[Gary E. Gould:]

Well, they only get better is what we've examined across our acreage position. We're seeing processes becoming more and more enhanced as we head deeper into the basin to the west. That happens in a lot of our plays, by the way.

[Subash Chandra:]

Yeah.

[Jack H. Stark:]

And what's great about these, say like – say the Meramec here, Subash, is that I mean this is porosity you can see on the logs. A lot of this stuff that we've looked at and worked with in the Woodford, I mean it's really tough to find the porosity on logs that you're dealing with nanodarcy perms and things and this is some reservoir rock, you can look at on logs and see it. So it's real encouraging both from volume in place to the recovery factors.

[Subash Chandra:]

Okay. Is it – so it's equally, would you say it's equally shaley and dry water wise as to the east?

[Gary E. Gould:]

Yes, in general, the areas – the wells don't recover much of their load. We go on – you'll hear us and other operators talk about, day two or three, we're making 500 plus barrels a day and 1,000 barrels on day four or five. The water has been driven out of this petroleum system during the generation phase is what we believe, and that's why the water doesn't flow back. So...

[Jeffrey B. Hume:]

It's completely different from the Mississippi play to the north.

[Gary E. Gould:]

Yeah, they couldn't be any more different really.

[Subash Chandra:]

Do you think you're recovering mainly – you think you're recovering mainly Woodford sourced hydrocarbons or do you think the Meramec plays a role in generation there?

[Gary E. Gould:]

Well, we're early in our evaluation, but our current belief is that the Woodford is sourcing the entire petroleum system here.

[Subash Chandra:]

Okay. As for the JV, I get it's a hot play, people want it. How do you sort of juggle assets sales versus JV? Are asset sales in 2016 off the table as a cash inflow? And a JV, is upfront cash sort of a necessary component to any transaction?

[Jack H. Stark:]

Well...

[Gary E. Gould:]

Go ahead, Jack.

[Jack H. Stark:]

I was going to say, we'll just keep our options open. I mean surely, more cash upfront would be beneficial to us because it gives us more optionality, it gives us some cash to work from and could pay down some debt. But in the end, we consider any kind of options.

[Subash Chandra:]

Okay. And asset sales?

[Jack H. Stark:]

I mean bottom line is just be value driven, what's the best value for us and our shareholders.

[Harold G. Hamm:]

And I think, we mentioned earlier the simplistic nature of this, I mean this is basically a new play – a whole lot (59

[Jack H. Stark:]

Right.

[Subash Chandra:]

Okay. And one final one for me. The $50 cash flow neutrality, others have cited it as well and they seek to hedge at $50. Is there intention on your part to hedge at $50?

[Harold G. Hamm:]

There's not.

[Subash Chandra:]

All right. Perfect. Thank you.

[Operator:]

Thank you. Our next question comes from Paul Grigel of Macquarie. Your line is open. Paul Grigel - Macquarie Capital (USA), Inc. Hi, good morning. As you guys talk about cash flow neutrality into 2016, and the roughly $1.7 billion number at 210,000, you mentioned another 5% to 10% of cost savings. Is that built in and is there any additional LOE savings built into those estimates?

[John D. Hart:]

We kept LOE and most of the variables are fairly flat with what we're experiencing. So there may be some upside to that for us. I think I would point to what we said, $1.7 billion might be a little bit of an outspend. So, I think you would probably see a level that's going to be less than that. Paul Grigel - Macquarie Capital (USA), Inc. Okay. And can you guys provide an update on...

[John D. Hart:]

That's why we give a lot of sensitivities on the ranges and stuff. So you can see the various variables that we're working through, but our plan and our target in this current price environment is to target neutrality. Paul Grigel - Macquarie Capital (USA), Inc. Okay. Definitely understood. Can you guys provide an update on the latest thoughts on what your corporate decline rate is either today or as you head into 2016?

[Gary E. Gould:]

This is Gary Gould, I can comment on that. Our corporate decline rate's in the mid 30%s and we'll be updating that more at year-end when we talk about year-end reserves. Paul Grigel - Macquarie Capital (USA), Inc. Okay. And then last one for me on differentials. Obviously, they've tightened up as mentioned in the guidance. When you look at just specifically to the Bakken, a lot more on pipe, you guys still have about 25% on rail. Are you seeing rail having to cut its prices and if so, is it through the rail providers or is it the end market refineries there?

[Jeffrey B. Hume:]

Well, we have – this is Jeff Hume. We have seen some of the rail costs go down. Cars are much cheaper than they were. We haven't seen much movement from the rail service itself, but I would expect some of that to happen as more and more trains are stacked, but there's still good demand from rail customers. Pipe is getting stronger, Line 9 is opening up next month going – Enbridge Line 9 going to Montréal and the Southern Access Pipeline going down to – Patoka is opening up, so you're seeing improvement in both Bakken and the Syncrude markets in that area. So I think we have additional competition up in the Bakken area. And the refiners are seeing the value of the refined barrel and they're paying for that. And so we're seeing differentials improve that way also. It's not just in transportation, but also additional value being passed to us from their realizations at the refinery. Paul Grigel - Macquarie Capital (USA), Inc. And is it your intention to always maintain some rail for flexibility going forward, and if so, is there a percentage?

[Jeffrey B. Hume:]

Well, we'll make – as always, we'll have a basket approach and we'll be reaching out to the best markets on a monthly basis. Paul Grigel - Macquarie Capital (USA), Inc. Thanks for the time.

[Operator:]

Thank you. Our next question comes from Biju Perincheril of Susquehanna. Your line is open.

[Biju Perincheril:]

Thanks. Good morning. Quick question, clarification on the maintenance CapEx budget, does that assume that you work off the uncompleted well backlog at all or is that...

[John D. Hart:]

No, sir. That assumes that we – what we drilled, we complete next year. But that we keep the backlog relatively flat year-over-year. That's part of the optionality. Obviously, we could – for fewer capital dollars, we could go work that down and drill less. So, we still have a lot of flexibility and optionality, but what we've given you assumes it stays flat.

[Biju Perincheril:]

Okay. So, the eight rigs that you're running in the Bakken, what is the flexibility you have to drop those and in 2016 catch up on the backlog?

[Harold G. Hamm:]

Yes. In 2016, we'll be beginning with eight rigs beginning of the year and then over the year, we have five rigs out of the eight rigs, that our contracts expires we've flexibility to go down to three rigs.

[Biju Perincheril:]

And when you're talking about the $1.5 billion to $1.7 billion, is that assuming the current rig count stays flat or going down to those rigs?

[John D. Hart:]

Let me clear, we're getting a couple of numbers mixed up there. What we've got in our – if you look at our investor slides and what I said in the script, it's $1.5 billion to $1.6 billion, basically would be cash flow neutrality next year. That's assuming a little bit of a mix between a fewer rigs and putting some completion crews back in the different asset basin. So, it's working it down a little as Gary gave some reference too. The $1.7 billion that was, I think, the previous question and that would hold us flat at $2.10 billion to $2.15 billion, but right now I think we target the lower end to that range, the 200,000 Boe.

[Biju Perincheril:]

Got it. Thank you.

[John D. Hart:]

Sure.

[Operator:]

Thank you. Our next question comes from Matt Portillo of Tudor, Pickering & Holt. Your line is open.

[Matthew Merrel Portillo:]

Good morning, guys.

[John D. Hart:]

Hi, Matt.

[Harold G. Hamm:]

Good morning.

[Matthew Merrel Portillo:]

Just one quick follow-up on the STACK, in terms of your acreage breakdown, could you give us maybe a little bit of color around how much you think you've delineated so far with your well control on the Eastern part of Blaine County. And then I guess can – around that same comments how much acreage do you have kind of in Dewey and Custer?

[Jack H. Stark:]

I'll start out and just say that really because of well control out here, the existing well control and, Glen, you can give some more color on this. But we're actually – a lot of the reservoirs we're targeting in the Meramec and Osage are fairly well delineated. And so, we actually again best both of world with HBP acreage plus, penetration allow us to delineate the reservoir. But Glen, can you touch on just the density of growing well control?

[Glen A. Brown:]

Right. Part of the reason that our acreage is in the right place is its position for development of Woodford early, and through that process we have modern logs over a 105 digital logs that penetrated and we can study. In addition, there is 575 old, older logs that we also use, so this is not a – we know exactly where these reservoirs are. This is not exploration at this point. This is just definition. And this is really the world – a great class asset that we have and we're in our early innings in our drilling, but I think we're – we've advanced our understanding to a pretty high level over the last year in terms of where we're going.

[Matthew Merrel Portillo:]

Great. And then just a follow-up question on previous comment on service cost. Just curious, if you could comment specific to the Bakken, as we've heard from some of the service industry, they're continuing to kind of reduce activity in the basin, as they core up their own crews. How do you guys see access to service as the industry's slowed down, and as you head into 2016, particularly around the completion side of the equation, is there any risk that it may not be capacity available or you still feel very comfortable that there is plenty available at this point?

[Jeffrey B. Hume:]

There's plenty available. The key for any oil and gas company is going to be just communication far enough ahead of time to bring those crews back. And so that will not be a problem for us. There's plenty of spare capacity with activity down 60% for every crew running, there is 1.5 crews out there as far as equipment. And we're talking to service companies every day, and they're going to be able to get the people back. These are great jobs, so people are excited about coming back to our industry.

[Matthew Merrel Portillo:]

Thank you very much.

[Operator:]

Thank you. Our next question comes from Dan Guffey of Stifel. Your line is open.

[Daniel D. Guffey:]

Hi, guys. Two follow-ups on the Meramec. I guess, first, can you talk about potentials GOR increase over time from what you've seen out of your Ludwig well?

[Gary E. Gould:]

This is Gary Gould, and I can talk a little bit about that. On our Ludwig well, we have pinched it back. What we're trying to do is produce it the best way we can to maximize our value for the long-term. And so, what we find is when we pinch it back a little bit, we don't go below the bubble point as quickly and it keeps gas in the reservoir, which continues to provide energy to produce it. And so, those are some of the things we're testing right now, and we'll learn more about that over time.

[Daniel D. Guffey:]

Okay, great. And then, the first three wells, were they all landed in the same portion of the Meramec being either upper, middle or lower, obviously you guys have a thick reservoir there and then I guess the next four wells you're completing, are those going to be landed in the same zones or are they kind of tested – are you testing all different areas?

[Jack H. Stark:]

We drilled – our initial drilling program was focusing on acreage that we needed in HBP. So, it's all focused on one area and is primarily targeting the lower most bench of the lower Meramec. With the exception of the Marks where we actually drilled in the upper – the second bench up in the lower Meramec and then went down to the lower one in a toe-down orientation. We have drilled in areas where we have much thicker part of the section, but we're yet to complete those wells. That's the Bowden well and that's coming up soon. So, we're looking at different targeting intervals in it, from area to area, but it's very – really pretty consistent.

[Daniel D. Guffey:]

Okay. And then I guess acknowledging you guys are still trying the HBP 40% of the acreage, I guess when does it make sense to do a spacing pilot, which would be in the lateral spacing and I guess the STACK in staggered portions?

[Jack H. Stark:]

Well, we obviously like to try those things very early and integrate micro-seismic and core data. We are in the planning stages for that, but we're not ready to release any plans and dates for that at this point.

[Daniel D. Guffey:]

Okay. Thanks for all the details (70

[Harold G. Hamm:]

Thank you.

[Jack H. Stark:]

Thank you.

[Operator:]

Thank you. I am showing no further questions at this time. I'd like to turn the call back to Mr. Hamm for closing remarks.

[Harold G. Hamm:]

Thanks, everybody, for joining us today. We appreciate your interest in Continental and as we've had a wonderful performance this quarter and very, very solid performance by all of our staff and all of our teams, land, everybody included, it's been great. Thank you very much.

[Operator:]

Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program. You may all disconnect. Everyone, have a great day.