Continental Resources, Inc.
Q3 2016 Earnings Call Transcript

Published: 4 Nov 2016

[Operator:]

Hello, and welcome to the Q3 2016 Continental Resources Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session, instructions will follow at that time. And now I'd like to introduce your host for today's call, Warren Henry, Vice President of Investors Relations. You may begin.

[J. Warren Henry:]

Thank you, Towanda. And thank you, everyone, for joining us this morning on the call. I would like to welcome you to today's call. We have excellent results to discuss. For Continental, we'll start today with remarks from 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 and available for Q&A later will be other senior members of the executive management team including Jeff Hume, Vice Chairman of Strategic Growth Initiatives; Pat Bent, Senior Vice President-Drilling, Glen Brown, SVP-Exploration; Gary Gould, SVP-Production and Resource Development; Ramiro Rangel, SVP-Marketing; and Steve Owen, SVP-Land. Today's call will contain forward-looking statements that address projections, assumptions and guidance. Actual results may differ materially from those contained in 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 forward-looking statements made on this call. Also in this call, we will refer to initial production levels for new wells, which in most cases are maximum 24-hour initial test rates. We also refer to average 30-day rate in the Bakken. Finally, on the call, we will refer to certain non-GAAP financial measures. For a reconciliation of these measures to generally accepted accounting principles, please refer to the updated investor presentation that has been posted on the company's website at www.clr.com. With the preliminaries covered, I will turn the call over to Mr. Hamm. Harold?

[Harold G. Hamm:]

Thank you, Warren. Good morning, everyone, following a great game seven at World Series. Continental's third quarter 2016 was outstanding in several aspects with key strategic achievements in the Bakken, STACK, SCOOP, and Northwest Cana. Big milestone events will have profound impact on our performance over the next 18 months to 24 months. We achieved true milestones for Continental in the quarter. The first milestone is our shift to development in the STACK over pressured oil window. The outstanding results with the Ludwig unit density test demonstrated a template for development. Including the legacy parent well, the Ludwig unit as a whole had a total IP of 21,350 Boe per day, 70% oil from eight Meramec wells. This success is exciting for two reasons. First, it confirms our vision of STACK's resource development potential and the result demonstrates the prolific production uplift per unit we can expect as we develop this oil window. Continental has developed for developments – has identified for development 55 operating units in the portion of our oil window leasehold that we have de-risked at this current time. We are now drilling four of these units and are de-risking additional oil window leasehold. STACK production is an increasingly important catalyst to our production growth strategy. Production was up 21% quarter-over-quarter, and was a key contributor to record third quarter production of 88,250 Boe per day in the Southern Region here in Oklahoma. For perspective, this exceeds the average daily production for the company as a whole just five years ago. The key takeaway here is this, using the Ludwig as a template we're looking at more than 650 potential gross drilling locations in these 55 operating units assuming at least eight Meramec and four Woodford wells per unit. The size of the prize will continue growing if we further delineate and de-risk our STACK Meramec leasehold and additionally develop the underlying Woodford formation. We haven't to date emphasized Woodford log in STACK, but yesterday we announced several outstanding new Woodford wells. The Northeast Atteberry and Reece Jane wells IPed at 19.5 million cubic feet per day and 16.6 million cubic feet per day, respectively, with very strong flowing casing pressures. These are stout 2-mile lateral wells and they're obviously delivering high-volume gas production just in time for increased winter prices and demand. We began – milestone number two, we began harvesting our valuable Bakken uncompleted well inventory. We now are using our latest and best technological breakthroughs incorporating very large slick water stands with increased fan loading and multiple diverter per stages for superior results. We now have two completion crews in the Bakken and we're adding the third and fourth by year-end 2016. Our 14-month pause in Bakken completion activity since September 2015 has created real incremental value here. During this time, we built up our uncompleted well inventory, while testing and developing the very best enhanced completion technology to maximize our production and reserve potential across the field. Now, we're going to realize the increased value of that inventory as we target lowering it to a normal level by yearend 2017. The two enhanced completion wells announced yesterday, the Brangus North and Rath Federal, illustrate the value of our uncompleted well inventory and enhanced completions. They set Continental records for 30-day average production rates. Completion designs use a combination of diverters and large slick water and sand stimulation on these wells, providing a valuable template for future Bakken completions. Although it's early in their production history, we expect both wells will produce in excess of 1 million barrels of oil equivalent. Bringing forward the value of our uncompleted well inventory with great capital efficiency, I might add, will be a key driver of the company's production and cash flow growth in 2017 and 2018. We clearly have the inventory to support double-digit production growth for many years. We will be disciplined, however, and continue to keep CapEx in balance with cash flow as we execute our growth strategy. Milestone number three. We saw strong unit production from our May density project or latest density project in the SCOOP Woodford oil window. With this success, we are adding a large portion of our SCOOP Woodford oil window leasehold to our list of best-in-class assets ready for development, with the others being the SCOOP Woodford condensate core, the SCOOP Springer, the STACK de-risked area, and the Bakken core. I want to emphasize this point. We have the optionality to be in development in five strategic asset plays to target the best rates of return for the company and its shareholders. That said, we are continuing to expand this productive footprint in the Oklahoma plays with step-up and exploration drilling. Finally, along with these outstanding operating results in third quarter 2016, we've created significant value through debt reduction. Our goal is to reduce long-term debt to about $6 billion, which we see as a comfortable debt metric level for Continental. We plan to accomplish this with positive cash flow and the proceeds from additional non-strategic asset sales. Now, let's discuss here just a minute our macro view. World oil supply and demand have rebalanced, as we predicted earlier. The overall trend since summer, obviously with some choppiness and volatility, has been a continued reduction in U.S. supply and a gradual drawdown in world inventories. For their part, members of OPEC have come to the negotiating table just as supply and demand are rebalancing. It's interesting what two years of high-cost pain can accomplish. Consequently, even with week-to-week volatility, we see a disciplined, deliberate recovery ahead of us. We expect the overall market dynamic for the next several years will be slow, but steady growth in both supply and demand, with prices moving gradually higher. Regardless of OPEC's specific action at the end of November in Vienna, we believe world energy markets are at the turning point. For the first time since OPEC was founded 56 years ago, markets are increasingly driven by free market forces. Foreign producers will have less power to manipulate the crude oil market because there are multiple sources for supplied capacity growth, most notably the leading U.S. shale play. We and other producers have made OPEC policy less relevant to the world's energy markets. In this competitive environment, Continental is positioned exceptionally well to prosper its strong execution, best-in-class assets, and capital discipline. With that, I'll turn the call over to Jack Stark.

[Jack H. Stark:]

Thank you, Harold, and good morning, everyone. We appreciate you joining us on our call. As Harold pointed out, we have some impressive results to share with you once again from all of our plays. Last quarter, we focused on results from our step-out drilling and enhanced completions that significantly expanded the de-risk footprint of both STACK and SCOOP. This quarter, I will focus primarily on the density drilling results that are multiplying the value of our STACK and SCOOP assets. I will start off in STACK, where we couldn't be more pleased with the results of our first density test in the over-pressured oil window. The Ludwig density completed flowing at a combined peak rate of 21,350 barrels of oil equivalent per day from eight Meramec wells, or 2,670 barrels of oil equivalent per day per well. This includes seven new wells that flowed at an average peak rate of 2,650 barrels of oil equivalent per day, with flowing casing pressures ranging from 1,325 psi to 1,975 psi. Approximately 70% of the production was oil. These rates of flow pressures are right in line with the peak rate reported from the original Ludwig 22-15XH of 2,780 barrels of oil equivalent per day, back in August 2015. The original Ludwig well has produced a total of approximately 300,000 barrels of oil equivalent during its 338 days online and is currently producing 815 barrels of oil per day at 1,060 psi flowing tubing pressure, with 72% of the production being oil. Early performance from the Ludwig unit shows no interference between the wells. This density test includes four wells in the Upper Meramec, four wells in the Middle Meramec, spaced 1,320 feet apart and offset 660 feet between intervals with approximately 100 feet of vertical separation. Average lateral length was 9,700 feet. As anticipated, the cost for the Ludwig density test came in significantly lower, thanks to the efficiencies that come with pad drilling. The average completed well cost for Ludwig density wells came in at $7.8 million each. This compares to $11.1 million for the original Ludwig well last year and our current target of $8.5 million per well for a standalone Meramec well in the over-pressured oil window. Our drilling and completion teams have done a remarkable job lowering costs over the last year through multi-disciplined teamwork, technology, and execution. Given the Ludwig density results and the consistent performance from our previous step-out wells, we now believe approximately 47,000 net acres in the over-pressured oil window are de-risked and ready for unit development. This area is outlined on slide 11 in our slide deck and stretches approximately 20 miles from our Verona well on the east to our Frankie Jo on the west and includes 55 Continental-operated units. As Harold mentioned, extrapolating the Ludwig results to the undeveloped units in this de-risked area gives a glimpse of the added inventory and the potential production uplift that lies ahead from this portion of our STACK acreage. We currently have four unit development projects underway in this de-risked area, including the Blurton, Bernhardt, Verona and Gillilan units. These unit developments are planned to test up to five wells per zone. In addition, we have 11 unit development projects that are in the planning stage, potentially testing up to seven wells per zone in the Meramec. We already own water gathering and handling infrastructure in STACK from our legacy production, but to facilitate our anticipated growth, we are in a process of installing additional water gathering and handling systems, as well as a recycling facility. We're also making plans for additional gathering and mainline takeaway systems to handle the expected oil and gas production growth. And to expedite unit development, our teams are developing strategies to drill wells from both ends of these units and synchronize the stimulations. In addition to the Ludwig unit, there are a couple of other third-quarter achievements of STACK that I'd like to highlight. First, we completed another step-out well that further demonstrates the remarkable repeatability of the Meramec reservoir underlying our leasehold. The McBee 1-3H completed flowing 2,110 barrels of oil equivalent per day at 3,850 psi flowing casing pressure, and 58% of the production was oil. What's impressive about the McBee is that it's delivering this high rate from a 4,760 foot lateral. This well is located about 12 miles west of the Ludwig, further de-risking our assets. Next, I want to highlight the outstanding performance of four STACK Woodford wells that we completed in our Northwest Cana JDA, underneath our Meramec reservoir. The four new wells had individual peak production rates ranging from 12.4 million cubic feet to 19.5 million cubic feet of gas per day and flowing casing pressures ranging from 4,800 psi to 7,100 psi. Our nearby Lacretia well, it was the Lacretia 1-29-20XH, which we announced last quarter, has produced 2.7 Bcf from the Woodford in 230 days and continues to produce 8.8 million cubic feet of gas per day at 2,250 psi flowing casing pressure. I have to say these Woodford completions compete with some of the best wells being drilled in the country today. The key point here is that the future unit development throughout STACK will include not only the prolific Meramec reservoirs, but this outstanding underlying Woodford reservoir as well. As an added benefit, each of these STACK Woodford wells that we drill HBP [Held by Production] our Meramec rights that provide valuable information about the Meramec reservoir thickness and quality for future development. Now let's move on to SCOOP where we completed our May density test in the Woodford oil window. The May unit had a combined peak production rate of 6,880 barrels of oil equivalent per day from seven wells, for an average of 980 barrels of oil equivalent per day, per well, with 77% of the production being oil. This includes five new wells that average 975 barrels of oil equivalent per day. These wells are spaced 775 feet apart, with an average lateral length of 7,300 feet. These seven wells were completed with our enhanced completion design, with triple the proppant and 50% more fluid than the offset wells. And early-time performance from these wells exceeds offset producers and is in line with our new 1.3 million barrel equivalent EUR type curve for enhanced completed 9,800-foot wells in the SCOOP Woodford oil window. Given the May density project's success and previous step-out drilling, we now consider approximately 50,000 net acres in the Woodford oil window to be de-risked and ready for unit development. This is just over half of our position in the Woodford oil window, so again, there's upside to come. Now, in the Bakken, the big news is that we have elected to begin working down our uncompleted well inventory. We will have two stimulation crews completing wells next week, and plan to have a total of four crews completing wells by year-end 2016. John will provide more details here in a minute, but I wanted to add some color, really, to the Brangus North 1-2H2 and the Rath Federal 5‐22H wells that Harold mentioned earlier. The wells produced a company-record total of 52,000 barrels of oil equivalent and 43,000 barrels of equivalent in their first 30 days of production respectively. Compared to our standard completion, these wells were completed with two to three times the proppant volumes as well as diverters. Approximately 40 miles west, we also completed the Nashville 2-21H, Maryland 2-16 well with enhanced stimulation design. The wells had peak production rates of 1,400 barrels of oil equivalent per day and 1,265 barrels of oil equivalent per day respectively. The Nashville Maryland wells are outperforming their offsets, and are 900 MBoe equivalent type curve as well. The Nashville has produced 120,000 barrels of oil equivalent in 120 days, and the Maryland has produced 130,000 barrels of oil equivalent per day – total in 160 days. The two wells currently produce – continue to produce 700 barrels of oil equivalent per day and 900 barrels of oil equivalent per day respectively. These results further validate the quality of our uncompleted Bakken inventory, and demonstrate the potential production uplift that we can deliver at low cost. Now, before I turn the call over to John, I want to emphasize that our achievements over the past 24 months have enabled us to more than double the capital efficiency since 2014, while we reduced combined cash G&A and LOE to $4.97 per Boe, which ranks among the lowest of our peers. The graphs on slide 5 and 6 in the slide deck are there for the comparison. What's critical is, is that we believe this level of performance is sustainable going forward due to three key factors. Number one is the depth and high quality of our assets. The addition of STACK to our leading positions in SCOOP and the Bakken gives us deep, high-quality inventory with great optionality to develop over the next 10 years to 20 years. Number two is the structural efficiency gains we have achieved. As the number one driller in the U.S. for the last year, we have kept our technical and operating teams together and made great strides operationally that will benefit us for years to come. And number three is the fact that today we get 133% more barrels of oil equivalent for every capital dollar we spend compared to 2014. This is a direct result of moving to the Bakken core and the outstanding performance of our world-class assets in STACK and SCOOP. I should also point out that an underappreciated aspect of STACK and SCOOP is that these petroleum systems produce very little formation water. In fact, we recover only a portion of the fluid used to stimulate Meramec wells in STACK. In contrast, Permian Basin wells typically produce between 60% and 80% formation water. Not having to handle volumes of water in STACK and SCOOP significantly reduces our operating costs of course. Along the same lines, wells in the Bakken core also produce very little formation water, typically 15% or less. So this is the key reason Continental's operating costs are low and should remain low going forward. It's an added benefit of our best-in-class assets. With that I'll turn it over to John.

[John D. Hart:]

Thank you, Jack. Good morning, everyone. Revenue for the third quarter was $526 million, up 17% over second quarter of 2016. EBITDAX was $387 million, lower than the second quarter, but the second quarter benefited from the $97 million gain reported on the Wyoming leasehold sale, which closed in April. Continental reported a net loss of $110 million or $0.30 per share for the third quarter. Adjusted to exclude impairments, non-cash gains and losses on derivatives and gains and losses on asset sales, the net loss was $83 million or $0.22 per diluted share. Third quarter production totaled 207,840 Boe per day, down 5% from the second quarter. This decrease reflects our decision to curtail approximately 12,000 Boe per day in the Bakken during the two months of August and September due to lower oil prices. We estimate quarterly production would have been approximately 216,000 Boe per day had we not curtailed. We resumed full production in early October as oil prices recovered. We are currently producing approximately 214,000 Boe to 215,000 Boe per day. Our oil percentage in the third quarter was lower, primarily due to the curtailment of Bakken production and the significant size of the large Northwest Cana wells. As a reminder, we have a 50% carry in Northwest Cana, and these wells represent extremely high rates of return, as depicted on slide 8 in our slide deck. Moving forward, we estimate our oil ratio in October to be approximately 58% and 60% to 61% for the full year. As we are beginning to commence completion activity on uncompleted Bakken wells, we expect to see the oil ratio to continue increasing throughout 2017. Our oil-focused STACK pads will also enhance our oil ratio as evidenced by the Ludwig pad. As a reference point, we are a two-stream reporting company. If we were a three-stream reporting company, we estimate our liquids percentage would be 70%, significantly higher due to our liquids-rich gas stream. Despite lower production for the third quarter, our per-unit cost remained strong. Third quarter production expense was $3.50 per Boe, down from $3.72 per Boe in the second quarter. On an absolute basis, total production expense declined nearly 10% from the second quarter to the third from $74 million to $67 million, reflecting remarkable execution by our operating teams. Third quarter cash G&A excluding non-cash equity compensation was $1.63 per Boe, reflecting lower third quarter production and slightly higher employee expense. However, on a year-to-date basis, cash G&A per Boe, excluding non-cash equity compensation was $1.31 per Boe. This is well within our guidance range of $1.20 to $1.60 for the year. Our cash G&A is amongst the best in the industry due to our lean organizational structure and exceptionally productive assets. Total cash cost is calculated on our slide deck, inclusive of LOE, G&A, interest and production tax was $11.23 per Boe for the third quarter, consistent with the second quarter. Our low cash cost performance trend should continue beyond 2016. Non-acquisition capital expenditures totaled $239 million for the third quarter, bringing the year-to-date total to $768 million. Third quarter CapEx included completion cost of $16 million for incremental Bakken completions. Now, let's move on to guidance. Last evening, we revised a number of elements of our 2016 guidance, reflecting improving results and increasing completion activity in the Bakken and Oklahoma. This is the third time this year we have positively updated guidance as we continue to focus on enhancing our results. Changes in our 2016 outlook include an increase in production guidance to a range of 215,000 Boe to 220,000 Boe per day, higher by 5,000 Boe per day from the low end of previous guidance. This reflects strong results from Bakken and STACK wells, and is further testament to how well enhanced completions are working across our portfolio. We now expect to exit the year with production in range of 205,000 to 210,000 per day, which is a 10,000 per day increase from the low end of the guidance we provided in October. These numbers reflect the timing of pads and other completion activities we have coming on at various times over the next couple of quarters. Production expense guidance improved to a range of $3.50 per Boe to $4 per Boe, in comparison with the prior $3.75 to $4.25. Equity compensation expense improved to a range of $0.50 per Boe to $0.70 per Boe. And given the increase in completion activity, we have also increased the total number of gross operated wells with first production in the current year to an estimate of 119, up from 87 previously. These 32 incremental wells are focused in the Bakken, SCOOP and STACK, reflecting strong drilling efficiencies realized by our teams. We are maintaining the trend of exceptional capital efficiency across our operations. And then, finally, due primarily to the increased well completion activity and increased working interest, we have increased CapEx for the year by $180 million to $1.1 billion. Approximately 3/4 of the incremental capital is dedicated to incremental completions activity. Completing these uncompleted wells represent significant value to Continental, with a cost-forward rate of return on the incremental capital of approximately 100% at $45 WTI. We believe supply and demand have rebalanced, and this supports our measured increase in completion activity. We expect to have four completion crews in service in the Bakken by year-end 2016, likely increasing further next year. Accordingly, we now expect our uncompleted well inventory in the Bakken will be approximately 175 at year-end 2016 versus previous estimates of 190 to 195. Of note, the 175 excludes 15 wells that will be stimulated by year-end, but should commence first production in early 2017. So even though we're positively revising production and net completed well count for 2016, we expect to realize the most significant benefit of the additional CapEx in 2017. Our uncompleted well inventory represents a significant high-value asset for Continental. Depending on the pace of completion, we envision these wells represent the potential for 30,000 net Boe to 40,000 net Boe per day of incremental production growth, net to Continental. Even with higher 2016 CapEx, we expect to remain cash flow positive in the fourth quarter and for the year as a whole. If today's price held constant through year-end, we expect 2016 cash flow to be positive approximately $100 million, excluding divestiture proceeds. As market conditions evolve, we will adjust our pace of development accordingly, seeking to keep CapEx balanced with cash flow. Obviously, total positive cash flow will be significantly higher with divestiture proceeds of approximately $630 million in 2016. Continental's complete 2016 guidance can be found in our investor presentation posted on the website and also in yesterday's earnings press release. Our liquidity position remains robust. We have no near-term debt maturities and at September 30, we had $565 million of borrowings against our credit facility, down from $820 million at the end of July. It is worth noting that excluding working capital items and divestiture proceeds of $222 million, our third quarter activities generated excess cash flow of approximately $75 million. At October 31, the revolver balance had decreased to $295 million, reflecting continued improved cash flow and proceeds of $296 million from the sale of SCOOP leasehold announced in August, which closed in mid-October. In early October, we announced the redemption of our 2020 and 2021 notes dated for November 10, 2016, which was very well received by the market. Redemption of these bonds is being funded by divestiture proceeds realized this year. In the interim, until the redemption date, divestiture proceeds have been applied to the revolver immediately reducing interest expense. Redemption of these bonds will reduce annual cash interest expense by approximately $43 million, further benefiting overall cash flow. Total debt was approximately $6.560 billion at October 31, down from slightly in excess of $7.1 billion at December 31, 2015, so a reduction of about $550 million this year so far. We are targeting further debt reduction and expect to exit the year with long-term debt of approximately $6.5 billion. As Harold indicated, our eventual target is $6 billion in long-term debt, but we do not intend to sacrifice production growth to achieve this. We have additional opportunities for non-strategic asset divestitures, as well as continued application of excess cash flow to the balance sheet. Our 2017 planning is underway, and we expect to issue formal guidance in early January. Incremental completion activity through year-end 2016 sets us up very well to enter 2017 on a strong note. Clearly, the work down of our high-value, uncompleted well inventory will be a strong positive catalyst for 2017. In summary, we are set up very well heading into next year. With that, I will turn the call back over to Harold.

[Harold G. Hamm:]

Thanks, John. During the past two years, we used our exploration expertise to create enormous value in the STACK Meramec and Woodford, SCOOP Woodford, SCOOP Springer and Bakken plays when we needed it most. In addition, we've used our operations expertise to drive down operating costs and to create operating efficiencies that will drive high cash margins for years to come. Through it all, we kept retained focus on long-term goals, while Continental remained the most active operator in the onshore U.S. But looking back, it's also important to remember just what we didn't do in the past two years. We didn't dilute our shareholders by issuing stock at the lows. We didn't have layoffs, but kept our technical and operating teams focused on maximizing the company's future value, and we didn't sell strategic assets. Operating discipline, capital discipline, great execution, and an oil-weighted, decades-long inventory of high-quality assets, this is Continental today. In closing, I couldn't be more proud of our teams and what they continue to accomplish in the third quarter. My thanks to them. Operator, we believe we're now ready for questions.

[Operator:]

Our first question comes from Doug Leggate of Bank of America. Your line is open.

[Doug Leggate:]

Thanks. Good morning, everybody. I had a couple of questions, if I may. So, I'd like to pick up on the DUC completions in the Bakken, first of all. I mean you had signaled on the second-quarter call that you would be shutting in some oil production. So I appreciate the clarification there. But what I'm really interested in is the type curve is obviously on your recent completions is substantially above your 900 million barrel guidance, and I think you talked about $3.5 million as the 900 million costs so – or the 900 million barrel costs, if you see what I mean. So can you give us an idea what your completions are going to look like for the DUCs and just clarification on John's point, is that 30,000 barrels to 40,000 barrels a day an exit to exit expectation in 2017 for the Bakken? For the DUCs, I mean.

[Gary E. Gould:]

This is Gary Gould and I'll address the first part. As far as the DUCs go, our teams have done a great job as far as continuing to reduce our CapEx and our completion costs and have met our year-end target of $6 million per well as a completed well cost and at $3.5 million going forward for the uncompleted wells. And that's based on our enhanced completions that we've performed historically. So now this quarter what you see are new completions, they do have more diverter technology in them, as well as more of sand loading to them, and so there is a range of incremental costs associated with that, but what you see is we're also seeing significantly increased production that resulted in our two record wells for the company, in the Bakken. And so we're very early in that stage and we're going to continue to experiment with that. We see that our partners are also experimenting and so we will continue to evaluate that as we go forward. Overall, we will obviously only shift to these larger jobs assuming that rate return is even higher than what we currently model.

[Doug Leggate:]

So Gary, just to be clear. The 30,000 barrels to 40,000 barrels a day that John mentioned, does that assume the 900 million – the 900,000, sorry, type curve?

[Gary E. Gould:]

Great question. That assumes the old type curve, so there's some potential for uplift with that, with what we're seeing on these earlier completions using the diverters and the larger proppant, et cetera. So, there is some potential for further improvement to that. You asked how that number was derived, I would take it this way, take the DUCs as a company by their self, assume you start with zero production and you're building a new company just based on DUCs. If you apply roughly six to eight completion crews, you build up to a peak at some point, you're probably about 12 months out, and then you'll see that wedge coming off a little bit by itself, just decline from the earlier wells and mixing in. So, we look at them as almost a company in of their selves because they're a very sizeable asset with some potential for further uptick with what we're seeing on some of the newer completions.

[Doug Leggate:]

So John, my follow-up if I may, and I guess it's kind of the second part of my last question, also, this year you had 104 completions in your guidance. One expects over the higher capital efficiency in the Bakken and even that type curve upside. I know you haven't set a 2017 target yet, but The Street's got you flat on production for next year. Can you give us an early look as to what you think your growth outlook could be in 2017?

[John D. Hart:]

Sure. I think you see a – part of it depends on how quick you bring those completions and back in on the DUCs. But what you see is you certainly see significant growth in the second half of the year. The beginning parts of the year, the first couple of quarters, you may start to step into it a little more as you're starting to complete wells and drill, and then you start to bring those on line and you build up that momentum. But you see some – the potential for a lot of strong growth on the exit rate, year-over-year, will just depend on how quickly we start on some of that earlier in the period. We're working through those now. There's obviously a lot of variability in the market and we want to see how things settle out over the next few weeks before we come out with formal guidance for 2017. We've tried to give you certainly throughout the year and some more today, some incremental looks towards what 2017 could be. But we'll firm that up here near term.

[Doug Leggate:]

All right. Thanks for taking my questions, guys.

[John D. Hart:]

Absolutely. Thanks, Doug.

[Operator:]

Our next question comes from Brian Singer with Goldman Sachs.

[Brian Singer:]

Thank you, good morning.

[John D. Hart:]

Hey, Brian.

[Harold G. Hamm:]

Good morning, Brian.

[Brian Singer:]

On the Ludwig pad, is your optimism based on seeing the 24-hour rates in line with the initial well, despite the tighter spacing and the well cost point, or is there additional color you could share? And as we await additional data over time, can you remind us of what your expectations are for any haircut, if any, to performance versus the initial well to continue to remain optimistic?

[Harold G. Hamm:]

Yes, Brian, I'll start out and then Jack will weigh in I think. We've said before in this over-pressure oil window that these are absolutely the best wells that we've seen completed in my career. And certainly, when these wells came on just like the parent, just as quickly came into production, just as quickly. I mean, we talked about being robust in the way they come back. We recover just a portion of the stimulation fluid that's used here. But then, additionally, you step off 20-mile west to the Madeline and you see similar type production on that far west and it's not just this pad, but all of them combined that we've seen production from, it suddenly adds up to be tremendously exciting, particularly with the dominant leasehold that Continental owns in this area, and the fact that these can be drilled so expeditiously. With these wells not interfering with one another in their stimulation, we can drill with much smaller pads from both ends of the drilling spacing unit, and get them online a lot quicker without building up uncompleted wells.

[Jack H. Stark:]

Yeah. And, Brian, this is Jack. I'll add a little color and Gary may have something as well. But what was really impressive to me was not only that these wells came on at really just rates that were mimicking the original Ludwig well, but the Ludwig – the original Ludwig well was shut into the stimulation. And typically, you see those wells bashed and takes a while for production to come back. Within one week, the Ludwig was back up to its – what it was flowing when it was shut in. And so it just shows that it was not affected really at all by these offset STEMs. And it was – I mean it's back at what it was doing at over 800 barrels a day at 1,060 pounds flowing pressure. So I mean it's very, very impressive, and it says a lot about the reservoir to me. Underneath our acreages, there's been talk about – and people are still trying to figure – work their way through repeatability out here, and you don't necessarily hear people as strong about the repeatability as we are. But location matters and geology matters. And underneath our acreage, we're seeing very nice development of this, of the Meramec interval and we also have the advantage of the significant over-pressuring. And so all these things combined, really, play a big part in our, I guess, confidence going early here – early in the development of the play to take it to a development phase. And it's also a combination of all the history as well, working all these resource plays over the years, a little more comfortable stepping in with the results we've seen to this date.

[Gary E. Gould:]

And those are really similar comments I was going to say. Ludwig continued to – Ludwig number one, the original well, continued to produce very strongly. And I think that's a great indication of what we can see going forward. And so this Ludwig performance overall just gave us confidence in how we're going to expand this throughout this area, so.

[Brian Singer:]

Great. Thank you. That's really helpful. And shifting to the Bakken. The first step is completing the DUCs here. Just wondered what you would need to see, either from commodity prices or I guess anything further in the field, with the completion and well performance to consider actually increase your rig activity in the Bakken?

[Harold G. Hamm:]

Well, first of all, we're probably not going to – we're not looking at increasing rig activity. We've got a lot of uncompleted wells here. And we made the decision that once the fundamentals had shown that supply and demand had balanced, then we're confident on oil prices. And so, we start moving forward. And so, that's why we kind of contract two more crews and got everything going. So we feel confident where we're at with prices and our efficiency and making this capital investment up there. We feel confident in the direction we're going.

[Jack H. Stark:]

Yeah. Brian, the incremental dollars that we have that we put into the Bakken clearly would go into the DUCs because it's the most capital efficient thing we can do. And so, that's – so if you see us ramping anywhere, it's going to be ramping up of stim crews.

[Brian Singer:]

Thank you.

[Harold G. Hamm:]

Thank you.

[Operator:]

Our next question comes from Brian Corales with Howard Weil. Your line is open.

[Brian Michael Corales:]

Yes. Good morning, guys.

[Harold G. Hamm:]

Hey, Brian.

[Brian Michael Corales:]

In that Ludwig pad, are you all seeing anything, any difference between the upper and lower Meramec?

[Gary E. Gould:]

Well, Brian, we're monitoring that right now and intuitively you expect you might see a bit of difference, but we just don't have enough data to say at this point. But as far as performance and rates, gosh, they're really quite similar. So, at this point, can't give you any color on that. We need a little more history.

[Brian Michael Corales:]

And then is there a chance that you all could have three zones in the Meramec or is that just way too early?

[Gary E. Gould:]

No. In fact, we do have three zones in the Meramec across our acreage. I think what we've said here previously is that we don't necessarily see all three zones developed in one spacing unit. But on average, we're going to see at least two across the play. So, maybe that's why you think maybe we're only seeing two, but we clearly see three. And other operators even break it down into more than three zones, and conceivably that may prove out. This is our current view on the play, and we may find out that there's need to drill wells and maybe take it to a little bit, I guess I'd say, even a little bit more – I'm looking for a word, I guess more separated, more differentiated reservoirs here.

[Brian Michael Corales:]

Okay. And then one last one. On slide 14, I guess you all show some Meramec wells that are drilling or completing. And there's a few wells that look to be in Custer County, or one well in Custer. Are you all expecting to have oil shows there or is that all gas?

[Gary E. Gould:]

Well, we're moving down-dip significantly there and those wells are completing. And so we expect to see the gas content increase as you go down-dip. Just right now, we just – it depends where. That's why we're drilling wells right now, to define the hydrocarbon windows here. And at this point, we think about 40% of our acreage is in the oil window, 40% in the liquids condensate window and say 20% is in the gas window right now. So, that's our best understanding of the play at this point. That's exactly why we're drilling these wells, to demonstrate what the hydrocarbon windows look like.

[Brian Michael Corales:]

All right, guys. Thank you.

[Gary E. Gould:]

Thank you.

[Harold G. Hamm:]

Thanks, Brian.

[Operator:]

Our next question comes from John Freeman with Raymond James.

[John A. Freeman:]

Hi, guys.

[Harold G. Hamm:]

Hey, John.

[John A. Freeman:]

You all had mentioned that you want to look to reach a normalized DUC backlog at year-end 2017, and just given all the efficiency gains you all keep realizing, this is probably a little bit of a moving target question, but at least as we sit now, what would you consider a normalized DUC to rig ratio?

[Harold G. Hamm:]

It's according to what pad size that you have up there, but we think that we'll get this down to a base four rigs of less than 50 perhaps.

[John A. Freeman:]

Okay. Perfect. And then I just had a follow-up...

[Jack H. Stark:]

John...

[John A. Freeman:]

Go ahead.

[Jack H. Stark:]

That factors in not only the 175 wells we'd leave this year with, but the incremental wells that we would be drilling next year also. So, you'd have a pretty good delta there.

[Gary E. Gould:]

And the reason is that – this is Gary Gould, to add a little more color, the reason it might be that high is just because we're drilling a lot of wells on pad. So we're going to continue to work on how we can do that more efficiently. So it might not need to be that high as we're running four rigs. And then also just a little more color, we're drilling about 18 wells per year for a rig. And a standard stim crew will complete about three wells per month. So it helps you get that standard stim crew to rig count average.

[John A. Freeman:]

Got it. And then just one follow-up to what Doug had asked earlier. On these huge upsides you're seeing on these enhanced completions in the Bakken, how much more do you really need to see at this point, before you basically going forward, everything is sort of completed with these enhanced completions? Because some of these have been online a good while and they're just – they're crushing your curve.

[Gary E. Gould:]

Yeah, they really are. We're seeing it. I think we're confident in what we have. We've got wells that have been on long enough, but we are seeing the difference in IPs and 30-day rates and then we've got some that we reported a while ago, it's been six months, 108 days. So we're seeing the uplift with these high volume slick water jobs and increased sand loading and, of course, more stages. And certainly these diverters, we're very excited about that, what we're seeing using those, and it's been about five per stage and we think it's working. So it's doing the job on the rock that we want done and we'll work with it later. So that's going to be more work, but -

[John A. Freeman:]

Would it be safe to say that when you all report year-end results, we'll get basically kind of an update on what we should be doing instead of this $3.5 million completion cost on a standard frac design? We'll get basically kind of an updated number that we'll be able to use at that time?

[Gary E. Gould:]

Yes. This is Gary Gould. Yes, we'll have another quarter behind us and when we look at results, we look at not only our own results but industry results also. So give us another three months and we'll give you some good color on forecast for next year.

[Harold G. Hamm:]

On both sides of the equation.

[John A. Freeman:]

Perfect. Thanks, guys, for everything.

[Harold G. Hamm:]

Thank you, John.

[Gary E. Gould:]

Thank you.

[Operator:]

Our next question comes from Arun Jayaram with JPMorgan. Your line is open.

[Arun Jayaram:]

Good afternoon. I was just trying to put into context, you guys talked about 47,000 acres have been, call it, completely delineated. How do we think about the ability of that fully delineated position to expand beyond your broader acreage position? And perhaps you could walk us through some of your thoughts on delineating acreage outside of this 47,000 acres?

[Jack H. Stark:]

Okay. This is Jack again and Glen you may want to follow up if you have any other thoughts. But if you go to page 11, you can see the area we've outlined that we are saying is de-risked. And this is really where the most concentration of our drilling has been up to this point from a de-risking standpoint. You got the Frankie Jo on the west side and the Verona on the east side, as we mentioned. They've got about a 20-mile stretch there and it's about what, 10-miles north to south. And so we're very comfortable in that area. And I think that you'll actually see the orange dots on there, those are other wells that are waiting on completion. And so you combine those with the other sub-surface control we have out there, and I think this play will go into a de-risk mode a lot quicker than most. And it's just because of the sub-surface control that already exists. There's several hundred wells that have penetrated the Meramec section out here already. And as I've said before, consider basically the play to be de-risked geologically, we're just demonstrating the hydrocarbon windows and the deliverability is. And the knowledge we're gaining up here really more the over-pressure oil window, plus these additional step-outs, will really – I think you'll find it accelerate the de-risk much more quickly than most. Glen?

[Glen A. Brown:]

This is Glen Brown, and I would add to that that we mentioned earlier in the call that we have five rigs associated with our SK JV, which is developing the Woodford. And that is, of course, below the Osage and Meramec reservoirs out here. So every one of those wells, we gain logs, we gain samples, we gain shows. We're building and adding to this already 600 well database with over 100 modern shale logs, sweep logs. And we are further defining that even though we're going into development mode to the east.

[Harold G. Hamm:]

And I might add that you shift to the development here in the STACK so quickly because of existing infrastructure. It's an area that had a long-time history, legacy production out here. So pipelines are there for gas, for oil. We can – and we have – actually have water handling as well out there from our legacy well. So this could go quickly into development.

[Glen A. Brown:]

One thing I would add – this is Glen Brown, again. This box that we put down to you is not our complete oil window development. It's only a portion of it.

[Arun Jayaram:]

That's helpful. And just I know you're not going to give us your thoughts yet on 2017, too premature. But how are you thinking I guess at a broad level how the SCOOP and Northwest Cana could compete for capital relative to the Bakken DUCs and what you're doing in the STACK?

[Harold G. Hamm:]

Well, we've looked at that. We must say that the DUCs are very efficient way of doing this and we've targeted the development of those are – the completion, all of those DUCs over a year's time and – which allows us to go forward with everything we're doing in STACK and SCOOP. Everybody else is going to be ramping here, we're not. We are very active operator. We've been active and we think we can keep cost in line as prices come up. So in this area, we don't have to ramp up. We have been as active for a long time.

[Jack H. Stark:]

Yeah. And we've got 19 rigs going now, most onshore in the U.S., and Gary talked about the efficiencies that you're seeing with those earlier. So we don't need to do anything in that perspective. But with the DUCs and what we're already doing, with the depth and quality of the assets and the uplift that we're seeing in some of these from a productivity standpoint, I think you'll be very pleased when we do come out with 2017 numbers and what we'll be able to do with those.

[Arun Jayaram:]

Great. Thank you very much.

[Harold G. Hamm:]

Thank you, Arun.

[Operator:]

Our next question comes from David Tameron with Wells Fargo Securities.

[Harold G. Hamm:]

Hi, David.

[David R. Tameron:]

Hi. Just building on the last question, if I just think about and I know you said you're not going to put any new rigs to work in the Bakken. But how would new drills, if I think about the Woodford versus the STACK versus the Bakken, how should we think about just returns across those three plays? How would you rank order those?

[Jack H. Stark:]

You can go to slide 8. I don't know if you've got the slide deck to go to slide 8, but, I mean, from a rate of return standpoint, the STACK Meramec over-pressured is well over 100% rate of return at $50. And by comparison, the Bakken, you're dealing with about 40% rate of return at $50. And so – but the DUCs, obviously are through the roof. They're over 100% rate of return at $40, really. So, all I'm going to say is that they're – we're seeing just some outstanding returns on really all of our assets, and it really comes down to – to me, it's basically keeping operational efficiencies going in these areas and keeping our momentum going in each of the areas. And so when it comes down to it, the DUCs and what we're doing in southern or down in Oklahoma between SCOOP and STACK really are topnotch.

[David R. Tameron:]

Okay. And if I just think about the 1,000-pound frac in the Bakken or 1,000-pound per foot, is there upside to that number as far as kind of go forward. Should we be thinking about potentially a higher number, when you're doing these same jobs in April, May, or how should we – or have you kind of hit the limit up there with the 1,000 pound?

[Gary E. Gould:]

Yes. This is Gary Gould. No, we're just starting to step into it, so have also tested 1,500 pounds per foot. We're testing 2,000 pounds per foot. So we're going to just keep moving up and then try to dial back to whatever the optimum best economics are.

[David R. Tameron:]

Okay. That's all I got. Thanks for the color.

[Harold G. Hamm:]

Thanks, David.

[Gary E. Gould:]

Thank you.

[Operator:]

Our next question comes from Ed Westlake with Credit Suisse. Your line is open. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) (58

[Glen A. Brown:]

This is Glen Brown and we have high hopes for our wells in the southern area, we have a high – if you recall, we talked before about the importance of the differences between the acreage in Lane doing Custer and that over to the east, that's in the normal pressured area. We have – the type of pressures that we have, up to three times the pressure that you'd have over to the east and you have thicknesses that are more than double form what we have over to the east. The expectation is that these results will be exceptional. It's just a little too early at this point to share those early results and we look forward to sharing them with you in the future. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) All right. And I guess what the broader strategic question is, with the work that you've done to improve completions in the Bakken, which has obviously brought more of the inventory into an economic zone at lower prices, and with the work you're doing in the STACK, maybe just an update in terms of other disposals that you might be able to do around the edges of the portfolio to kind of eat into the net debt position.

[Jack H. Stark:]

We've got 20 years to 30 years of inventory. So we've got a very deep base and some of the assets we've sold this year just weren't strategic to us. The variant SCOOP for instance is a nice area, but it was in our position was largely non-op, 65% non-op. What we sold in Wyoming, I would be willing to bet that it wasn't an analyst or an investor that even knew we had a position out there and that was a $100 million asset. We've still got 40,000 acres there. Across our portfolio, we've got things that is within our core positions that's longer out in terms of term, of when it would fit into our development portfolios. Our net asset value calculation or other things are just beyond that, and then we've got some positions in nice assets, but they're outside of some of those core plays. So we've got a good mix. I don't think we want to be too specific about individual assets now. But I would say there a number of things we continue to work on today and I think we obviously put the numbers out there in totality. So we feel good about our ability to realize those. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Thank you.

[Jack H. Stark:]

Certainly.

[Operator:]

Our next question comes from Steve Berman, Canaccord. Your line is open.

[Stephen Fred Berman:]

This is mostly a Bakken question, but I guess it could also be relevant to Oklahoma. I was on a call earlier today, with a company who is also the dominant player in the particular basin, said they are locked in 70% of their drill and complete costs going forward through the end of next year. Given your outlook on oil prices, I'm wondering if you share any concerns about service costs, and have you looked at possibly doing something similar, in terms of locking those in, as we move forward here?

[Harold G. Hamm:]

Well, let me try that. One thing we've had is very long-term relationships with vendors through this downturn. Sometimes we were the only ones active almost within a couple of these plays, some of these areas. I just don't feel that we're, number one, going to be gouged going forward by these vendors. And they have to run their business, but we found that these relationships have mattered in the past, and we think they will in the future. Gary, you want to weigh in on that?

[Gary E. Gould:]

Yeah. I might add that our teams have been reporting on our operational efficiencies every quarter for quite some time now, and the teams have gone through and looked at how many of our cost reductions have been associated with those that are going to stay long term with us regardless of what pricing does. And over half of what we have in place that we've seen over the last – half our overall cost reductions, we've seen over the last years are going to stay with us because they're operational. They're structural. They're things we've changed in how we drill or how we complete wells or how we've also increased the reserves associated with that CapEx. So, again, most – over half of our cost reductions have been structural in nature.

[Stephen Fred Berman:]

Very helpful. Thank you.

[Harold G. Hamm:]

Thanks, Steve.

[Operator:]

Our next question comes from Subash Chandra of Guggenheim.

[Harold G. Hamm:]

Hello.

[Subash Chandra:]

Hi. Good morning. Glen had mentioned the Osage, and he's got a very nice presentation out there. So what are your thoughts there on testing it?

[Glen A. Brown:]

Well, I did give a talk at the DUG conference here last week. In general, I think that the Osage is in earlier innings as compared to what the Meramec is. As you recall, the Meramec started in the shallower areas over there in Kingfisher and Canadian County. It's pushed itself further to deeper depths, higher pressure and basically into the thicker zones as we walk to the west. A very similar story is happening up to the north in the Osage area. There were some interesting early wells as you're up to the north outside of the over-pressure. And we're seeing now that drilling walking back to the south, where, again, it gets thicker in the Osage, and gets to higher pressure in the Osage, and we would expect that we'd have a deeper gas. We'd have multiples of those types of completions, just like we did in (65

[Subash Chandra:]

Right. Got you. Can you see that getting into the drilling program, the appraisal program in 2017?

[Glen A. Brown:]

Well, I think there's – I think it's underway with different outside operated activity. There's many wells that we are in, and we're monitoring that, seeing some early results that we think are impressive. And how that comes into our drilling plans will just evolve and keep that fluid in 2017.

[Subash Chandra:]

Okay. My second question is, I appreciate your 2017 guidance is still fluid. But you do have this build-up in completion crews and a plan, at least for the first half of the year. So what sort of baseline expectations do you think it's fair to use, in terms of, say, first-half volumes and a CapEx run rate? I mean, is it fair to say that the 4Q CapEx run rate is a good one to use into the new year, and the exit rate is a good number to use into the new year?

[Jack H. Stark:]

You know what, I think, going into the holiday season, I think it's good to have expectations, and it'd be good to open that release in early January. It's a little early to give you some of that data now. We feel good about our potential for 2017. I think we feel very good. I think you are going to see results that you'll be pleased with. We're working through a lot of items now. Just a number of pads going into STACK, balancing that, balancing in completions activity in the DUCs, and the pace of that. So we're looking forward to a very strong 2017. But as far as giving you more parameters now, obviously, we're generating significantly more cash flow. We'll be targeting somewhere in a cash flow neutral vicinity, but that gives us a lot of capital. And as Harold said earlier in his script, he referenced several years of double-digit growth, and I think we're setting up for a good period. And significantly, as we move into that back half of the year, you'll see a lot of that growth coming in the front half. You'll be starting it up.

[Harold G. Hamm:]

And, Subash, let me add just one other thing. We still have numbers evolving. One of the things that have really excited us about these pads out here in STACK, Ludwig and Blurton, Verona, is that we're seeing costs come down tremendously. And with the efficiencies of these ECO-pads that we drill from, we knew there would some – quite a bit of efficiencies there. But from where we were at, $11 million earlier down to less than $8 million now, we've seen a tremendous reduction, and we think that'll continue through the next several wells. So that's some of the workings that'll go into this next budget preparation.

[Jack H. Stark:]

Yeah.

[Subash Chandra:]

Okay. Terrific. And just a final one. So that southwestern step-out, you referenced I think you said early days, in some half (1

[Jack H. Stark:]

I'll take it, Glen. As we talked about here last week down here at the DUG conference, we happened to bump into each other. I know that there's a lot of interest in what's going on there. And the fact is that we're working on the wells, completing wells and taking care of some strategic things that we need to get finished up. So anyway, so right now, when we're comfortable we've taken care of business down there, we'll be talking about it. You know us. I mean, we've always put out our numbers. And so we – trust me, we've got some strategic reasons why we're doing so.

[Subash Chandra:]

Thanks much, guys.

[Jack H. Stark:]

Thank you.

[Operator:]

Our next question comes from Neal Dingmann with SunTrust.

[Neal D. Dingmann:]

Hey, Harold, maybe for you or Jack, you mentioned several times about being the most active operator onshore U.S. With that said, have you approached some of the service companies? I'm wondering about been able to either lock in some of the costs here? I guess two questions. One, just your comments on maybe how quickly we've heard others say about potentially service costs starting to accelerate as 2017 begins. And then secondly, if that's your thought, are you able to lock in on either the drilling or completion side, given the size of your operations versus some others?

[Harold G. Hamm:]

One thing we've done is use some of these companies to bundle their services for greater efficiencies from everything from bits to stimulation work. And that worked well for us. We think we can keep those companies in a – they've gained a lot from it as well during that process. So actually, our drilling cost, we have some of these contract rigs come off will naturally be lower, back to market rates. So, we think we're going to be pretty good with costs because we're in active areas already, it's not that it's going to be ramping up here.

[Jack H. Stark:]

Yes.

[Harold G. Hamm:]

I know other plays may ramp up to cause some pressure, but I think we're in good shape.

[Jack H. Stark:]

Yeah. I was going to say – this is Jack. I was just going to say that we're kind of unique in that regard because we're the most active driller, we have 19 rigs that are on contract but 75% of those come off this year. So, we'll actually see downward pressure on price per rig versus upward pressure as many other people are seeing. So, that puts us kind of in a unique spot in the industry.

[Neal D. Dingmann:]

Jack, is there anything on the completion side? I guess Harold mentioned about bundling. Anything on the completion where you can lock things in, or with services, that's just tough to do now?

[Gary E. Gould:]

This is Gary Gould. And we negotiate very hard with our activity levels. We're a premier service – premier oil and gas company for the service companies to work with. And so, we have very good relationships with them. And in my discussions with other companies, they continue to bring additional equipment into the industry, had a call as recently as yesterday with a company that wanted to start to work for us. And so, I think that the demand for this equipment will continue to add more supply and help keep the costs down.

[Neal D. Dingmann:]

Good color, Gary. And then just lastly, just on that slide 14, a lot of talk on that today. Are you currently adding rigs or acreage as you continue to get further northwest, say up into Dewey or even north of Dewey County?

[Harold G. Hamm:]

Steve?

[Steven K. Owen:]

Yes. We are continuing to add acreage through acquisitions and leasing. Just to give you a little color, this quarter, we've had over 40 acquisitions in the entire STACK area and acquired over 10,000 acres. So we continue to hit it hard and we'll do so.

[Neal D. Dingmann:]

Very good. Thanks, gentlemen.

[Harold G. Hamm:]

Thanks.

[Operator:]

Our next question comes from Pearce Hammond with Piper Jaffray. Your line is open.

[Pearce Hammond:]

Yes. Thank you for taking my questions. Just two kind of quick housekeeping questions. Number one is as we head into 2017, what would you estimate your base decline is in the Bakken on your PDP?

[Gary E. Gould:]

This is Gary Gould. It's in the mid-30%s, around 35%, plus or minus 3% for PDP.

[Pearce Hammond:]

Excellent. Thank you. And then my second one is...

[Gary E. Gould:]

That's probably a little shallower than that now just because we haven't done as many completions. Year one, you get a rate more akin to that. But we haven't been as active on the completion activity from an overall perspective.

[Pearce Hammond:]

And so, for the whole, for all your production at year-end 2016 in the Bakken, it's not the mid-30%s, you're saying it's shallower.

[Harold G. Hamm:]

Yes. We could get back with you with the exact numbers across – you're asking across the company?

[Pearce Hammond:]

Or just in the Bakken specifically. We can take it up offline. But thank you, Harold. And then my follow-up question is related to the completion cost for completing the Bakken DUCs. Is that with the enhanced completions, or is that just kind of your standard design?

[John D. Hart:]

This is still the current standard design. And so we will be looking at both the incremental production as well as the incremental capital and provide more color on where we land for 2017 budget at our next quarterly earnings.

[Pearce Hammond:]

But what would be the completion cost on those enhanced completions?

[John D. Hart:]

There's a range because we are testing a range of different items. And so...

[Pearce Hammond:]

I see.

[John D. Hart:]

... it's very hard to specify. We continue to work to look for optimum at a level that will give us even a higher rate of return than what we're already seeing.

[Harold G. Hamm:]

We might give a well or two that we have – we've seen as much as up to $7 million with some of the work that we've done.

[John D. Hart:]

That's correct.

[Pearce Hammond:]

Thank you very much.

[John D. Hart:]

Total well cost, not the incremental.

[Harold G. Hamm:]

Yeah, total well cost.

[Operator:]

Our final question comes from Biju Perincheril with Susquehanna. Your line is open.

[Biju Perincheril:]

Thanks. Good afternoon. I had a question on the density pilots in the STACK. So in the Ludwig, you're drilling the upper and the middle sections, and the subsequent pilot is testing the upper and lower. Is that based on what you've seen from the Ludwig, or do you think the sort of the prospective zones can vary, that those wells are in pretty close proximity in that short distance, they can vary?

[Jack H. Stark:]

Yeah. What you're just seeing there is just – you remember, I mentioned there are three members or three zones within the Meramec that we're targeting in here and they aren't necessarily all three developed in every one of the units. And on average, we expect to see about two of these intervals developed in each of the unit. And so what we're targeting in here on these are really the best developed intervals in each of these units. And so, in each of these right now, we're seeing that there are two like you can see pretty much across here, pretty much two on average per drilling spacing unit.

[Biju Perincheril:]

Okay. So even within the section, you could see variation as to which of the three is best developed?

[Jack H. Stark:]

Well, not really as much in the section but across the play. Within a unit, you're typically seeing kind of continuity of the reservoir. But as you go across the play, some areas you'll have an upper and a lower. Some areas, you'll have an upper and a middle and other places, you just – you'll have maybe an upper by itself even, way off to the east. So anyway, so I just think that just recognizing what we're targeting here, what we think are the most prolific zones, really you could put a wellbore anywhere within this petroleum system and make a well. What we're trying to do here is target the most – basically the highest deliverability areas within the reservoir.

[Glen A. Brown:]

If I might add though, this is Glen Brown. We're actually, despite these being really incredible results, this is actually in the thinnest portion of our interval that we target. Everything we're going to do is going to be thicker as we go down to the south and west in our intervals. And so we're dealing with kind of specific cases here and really some of what we're doing there is trying to establish two wells in a unit versus one like in (78

[Biju Perincheril:]

Okay. Got it. And then my second question was – appreciate you don't want to get into any of the well details on that southwest portion, but would you expect phase windows to be different, if you're looking at, let's say, the Meramec versus the Woodford?

[Glen A. Brown:]

Well, I think there's – we're gathering data in that regard, and there's certainly a potential for that to occur.

[Biju Perincheril:]

Okay. Thank you.

[Glen A. Brown:]

Look at the historic Woodford production that's underneath some of our given areas, and you can see that it's oiler directly above.

[Operator:]

Ladies and gentlemen, that concludes our Q&A session. I would now like to turn the call back over to Mr. Warren Henry for closing remarks.

[J. Warren Henry:]

I'd like to thank everyone again for joining us today. If you have further questions, please give us a call, as you normally do. We'll be glad to work with you. But with that, we'll conclude today's call. Thank you very much.

[Operator:]

Ladies and gentlemen, that does conclude today's conference. Thank you for your participation. You may now disconnect. Have a great day.