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Edited Transcript of CLR earnings conference call or presentation 30-Oct-18 4:00pm GMT

Q3 2018 Continental Resources Inc Earnings Call

ENID Nov 2, 2018 (Thomson StreetEvents) -- Edited Transcript of Continental Resources Inc earnings conference call or presentation Tuesday, October 30, 2018 at 4:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Gary E. Gould

Continental Resources, Inc. - SVP of Production & Resource Development

* Harold G. Hamm

Continental Resources, Inc. - Executive Chairman & CEO

* Jack H. Stark

Continental Resources, Inc. - President

* John D. Hart

Continental Resources, Inc. - Senior VP, CFO & Treasurer

* Josh Baskett

Continental Resources, Inc. - VP of Oil & Gas Marketing

* Patrick W. Bent

Continental Resources, Inc. - SVP of Drilling

* Ramiro F. Rangel

Continental Resources, Inc. - SVP of Marketing & HR

* Rory R. Sabino

Continental Resources, Inc. - VP of IR

* Tony Barrett

Continental Resources, Inc. - VP of Exploration

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Conference Call Participants

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* Andrew Elliot Venker

Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil and Gas Exploration and Production

* Arun Jayaram

JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst

* Bradley Barrett Heffern

RBC Capital Markets, LLC, Research Division - Associate

* Brian Arthur Singer

Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst

* Derrick Lee Whitfield

Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst

* Douglas George Blyth Leggate

BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research

* Jeanine Wai

Barclays Bank PLC, Research Division - Research Analyst

* Marshall Hampton Carver

Heikkinen Energy Advisors, LLC - Founding Partner and Director of Research

* Matthew Portillo

Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - MD of Exploration and Production Research

* Neal David Dingmann

SunTrust Robinson Humphrey, Inc., Research Division - MD

* Nitin Kumar

Wells Fargo Securities, LLC, Research Division - Senior Analyst

* Robert S Morris

Citigroup Inc, Research Division - MD and Senior U.S. Oil and Gas Exploration and Production Analyst

* Ryan M. Todd

Simmons & Company International, Research Division - MD, Head of Exploration & Production Research and Senior Research Analyst

* Subhasish Chandra

Guggenheim Securities, LLC, Research Division - MD and Senior Equity Analyst

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Presentation

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Operator [1]

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Good day, ladies and gentlemen, and welcome to the Q3 2018 Continental Resources Earnings Conference Call. (Operator Instructions) As a reminder, this conference is being recorded.

I would now like to introduce your host for today's call, Rory Sabino, Vice President of Investor Relations. You may now begin.

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Rory R. Sabino, Continental Resources, Inc. - VP of IR [2]

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Good morning, and thank you for joining us. I would like to welcome you to today's earnings call. We'll start today's call with remarks from Harold Hamm, Chairman and Chief Executive Officer; Jack Stark, President; and John Hart, Chief Financial Officer. Also on the call and available for Q&A later will be Jeff Hume, Vice Chairman of Strategic Growth Initiatives; Pat Bent, Senior Vice President, Drilling; Gary Gould, Senior Vice President, Production and Resource Development; Steve Owen, Senior Vice President, Land; Ramiro Rangel, Senior Vice President, Marketing and Human Resources; Tony Barrett, Vice President, Exploration; Josh Basket, Vice President, Oil and Gas Marketing; and Adam Longson, Director of Commodity Research.

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 SEC filings for additional information concerning these statements and risks. In addition, Continental does not undertake any obligation to update forward-looking statements made in this call.

Also this morning, we will refer to initial production levels for new wells, which unless otherwise stated, are maximum 24-hour initial test rates. We will also reference rates of return, which unless otherwise stated, are based on $70 per barrel WTI and $3 per Mcf natural gas.

Finally, on the call, we will refer to certain non-GAAP financial measures. For 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 that, I will turn the call over to Mr. Hamm. Harold?

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Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [3]

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Good morning, everyone. Thanks for joining us this morning. The third quarter of 2018 proved to be a very straightforward validation of Continental's overall plan for the year. We saw strong pricing for crude oil averaging nearly $70 WTI for the quarter and natural gas prices above the normal range, validating our decisions to remain unhedged with our crude oil and to curtail our natural gas production in the second quarter until market recover.

Along with record production from the Bakken, delivered by Continental teams, net income for the quarter was $314 million, leading consensus. The results of the third quarter began to show the benefits of our decision earlier this year to shift to 95% of drilling activity to our crude oil development projects.

In all 3 operating areas, Bakken, SCOOP and STACK, our teams delivered on unit development with great expertise while maintaining one of the lowest LOEs per BOE in the industry amongst select oil-weighted peers and delivering on our promise to bring on our new wave of oil growth for the company in the second half of 2018. Approximately 40% of our Bakken wells, this year, will be brought on in the fourth quarter 2018 as our teams took advantage of the long warm days of summer with drilling complete wells starting out in the third and fourth quarters as well as 2019 to reflect new oil-weighted growth.

If you'll recall last quarter, we talked also about our rationale for shifting our focus to oil and accelerating growth in the year-end, having recognized an opportunity in the market. While we remain a highly-disciplined company with the primary focus on capital-efficient growth and corporate returns, it is an appropriate time to increase our production growth rate, taking advantage of our inventory and infrastructure within the Mid-Continent and Bakken regions.

One of the major benefit from horizontal drilling of large-scale resource play, such as the Bakken, that I've witnessed during my 50-year plus as on explorationist, is that it has removed much of the drilling inventory and supply side concern from the equation. At least that's the case with us here at Continental. It enabled us to accelerate or decrease growth as is warranted. It also gives us the capability to project future activity with a level of confidence never before thought possible in this industry. Our teams are developing a granular update now to our 5-year plan, and we will discuss portion of this plan when we give 2019 guidance in early 2019. What I love about this plan is that it's all about the inventories that's on the shelf.

In October, we closed on our minerals deal with Franco-Nevada. John Hart will provide more details regarding minerals later in the call. I want to say thank you to the Continental team, which originated this unique minerals model and have worked really hard to make a close and Franco's team for all of their hard work. We welcome Franco-Nevada aboard and view this transaction as a growth catalyst for both companies in the future.

On the macro side, we see further tightening of oil supply as the Permian Basin remains constrained while infrastructure and Middle East tensions are further elevated by some recent events. Thankfully, the narrative on oil supply can be returned -- they turned to the positive development and the U.S. has long-term dependence on foreign oil supply wanes due to our own ability to supply our needs domestically. Although not as financially robust, the natural gas market continues to expand and is showing signs of a much healthier future. Once again, we witnessed the instability of foreign oil supply and the need to put American oil and gas production first.

As we believe, 2018 is clearly proving to be a breakout year for Continental. Stronger commodity prices are rewarding our non-hedgeable position along oil price upside participation for shareholders and driving free cash flow approaching $1 billion for this entire year. The timing of the planned development of the SpringBoard oil project could not have been better as oil prices and demand have improved in an unhampered infrastructure area. Our years of technology advancement are paying great dividend as our teams are delivering excellent drilling and development results. All these results are just in time for the crude oil super cycle that is now underway in America.

Now I'll turn it over to Jack Stark for more details on our operating results.

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Jack H. Stark, Continental Resources, Inc. - President [4]

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Thanks, Harold, and good morning, everyone. We appreciate you joining us on our call today. Our third quarter production exceeded guidance, coming in at 296,900 BOE per day, up 22% year-over-year and 5% over the same quarter. We exited the third quarter producing approximately 304,000 BOE per day and oil production was on the rise. Oil as a percent of production in September averaged 57% and October is coming in around 58%. By year-end, we expect our oil percentage to approach 60%, as we anticipate approximately 10% growth in our oil volumes quarter-over-quarter.

This rapid oil growth is driven by 2 things: first, 60% of the third quarter Bakken completions that came on late in September; second, our teams are forecasting a wave of completions in the fourth quarter from the Bakken and our SpringBoard project. Up to 70 wells or approximately 40% of the Bakken wells we forecast to bring online in 2018 are targeted to come online in the fourth quarter. Much of the capital associated with these completions has been spent ahead of this ramp.

I might add these percentages do not include natural gas liquids since Continental is a 2-stream reporter. If we were to report on a 3-stream basis, we estimate our total liquids production would be 10% to 15% higher. For the year, we expect production to come in right around the midpoint of our guidance of 290,000 to 300,000 BOE per day.

The Bakken was a key driver to our third quarter production growth as our Bakken production reached a record level of 167,000 BOE per day, up 23% year-over-year and 6% over the second quarter. During the quarter, we completed a total of 42 gross operated Bakken wells that flowed at an average rate of 2,013 BOE per day. The results were in line with expectations and 2 of the wells meet our top 10 list of Bakken producers based on first 30-day average rates. We currently have 8 rigs drilling in the Bakken, which is up 2 from the second quarter, as we prepare for continued growth into 2019.

As many of you know, Continental is a leading oil producer in the Bakken field of North Dakota by a wide margin, operating approximately 12% of the crude oil produced in August based on state records. As the leading operator in the Bakken, we thought it would be appropriate to provide an update, from our perspective, of the potential that lies ahead for the Bakken field as a whole and for Continental. The implications for our shareholders are significant.

I will start out with the Bakken field and there are 3 main points I want to make: first is that up to 50,000 potential wells remain to be drilled in the Bakken field based on recent estimates from the North Dakota Industrial Commission. This is net of approximately 15,000 Bakken wells have been drilled to date. Through August 2018, these 15,000 wells have produced approximately 2.6 billion barrels of oil and are adding production at a pace of about 0.5 billion barrels of oil per year at today's rates. My second point is that Continental's technical teams now estimate that 30 billion to 40 billion barrels of oil could be ultimately recovered from the Bakken field. This is up substantially from Continental's original estimate of 20 billion barrels back in 2011. The big difference is based in technology. With today's completion technology, we are now recovering up to 15% and potentially 20% of the oil in place on a primary basis. This is substantially higher than the recoveries we thought possible back in 2011. And using our technical team's current estimates of oil in place of around 250 billion barrels of oil, a 15% recovery would result in 37 billion barrels of oil recovered. This may seem like a high number, but if you assume 37 billion barrels is produced from 65,000 wells, each well would only have to produce approximately 570,000 barrels to reach it. This is clearly a reasonable expectation for the Bakken wells on average. My third point is, thanks to technology, the Bakken field, as a whole, is performing better than ever, making it arguably the best quality oil play in the U.S. today. I say this based on several performance metrics, including the field's low GOR, relatively low water cut and low LOE, high rates of return and overall consistency and quality of the oil.

Now speaking specifically about Continental, there are 2 key points I want to make: my first point is that the performance of our Bakken wells and our operating efficiencies have never been better. Our top 10 30-day rate wells have been completed in the last 12 months, and today, we are drilling wells routinely in 12 days or less. Rates of return from our Bakken wells have doubled over the last year based on well performance alone, with wells often paying out in under 9 months. As proof, Continental's 2017 Bakken program, which included 133 operated wells, paid out by the third quarter of 2018. Now that's capital efficiency. My second point is a reminder that Continental has drilled about 1,700 Bakken wells to date and has over 4,000 operated wells remaining in inventory. It's a very high-quality inventory. For perspective, if you assume we proceed with a 10-rig drilling program, we would drill approximately half of this inventory up over the next 10 years. On average, we project that the wells drilled during this 10-year period would deliver an impressive 80% to 100% rate of return assuming $65 oil and $3 gas. Bottom line, the Bakken will be a key driver of our Continental's oil growth for years to come.

Now let's move to STACK, where we recently turned 3 fully developed Meramec units of production. These 3 units are the best performing Meramec units we have operated to date and validate the unit development model our teams have designed to maximize the value of our assets and the overpressured window of STACK. Now 3 units flowed at an impressive combined initial rate of just over 74,000 BOE per day from 18 2-mile equivalent wells. This included 31,000 barrels of oil and 260 million cubic feet of gas per day. On average, each of the wells flowed approximately 4,100 BOE per day.

The 3 Meramec units include the Jalou and Homsey units in the overpressured oil window and the Simba unit in the overpressured condensate window. All 3 units were developed with a total of 6 2-mile equivalent wells placed in both the upper and lower Meramec reservoirs. The Jalou units wells flowed at an average initial rate of 4,234 BOE per day with 58% or 2,470 barrels of the production being oil. On average, these wells are outperforming our 1.2 million BOE unit type curve by approximately 75%. At these rates, the Jalou wells also set an industry rate record for wells completed and fully developed units in the overpressured oil window of STACK.

The Homsey unit wells were also strong producers and flowed at an average initial rate of 3,521 BOE per day per well with 59% or 2,019 barrels of the production being oil. The Homsey wells are outperforming our 1.2 million type curve -- million BOE type curve by approximately 15%.

In the condensate window, the Simba unit wells flowed at an average initial rate of 4,622 BOE per day per well, including 621 barrels of oil and 24 million cubic feet of gas per day. These are outstanding wells that, on average, are outperforming our parent type wells, not a unit well, for the condensate window by approximately 35%. These results will help us design our model for optimal unit development in the overpressured Meramec condensate window going forward.

The performance of these 3 units emphasizes the quality of the Meramec reservoirs underlying Continental's acreage and the potential they hold as we begin to develop up to 65 operated units that remain to be developed in the overpressured oil and condensate windows of STACK. Now, there's been a lot of numbers here, so the details of the results from these units can be found on Slides 10 through 14 of our slide deck.

In SCOOP, our drilling and completion activities in Project SpringBoard are moving along on schedule. 17 of the 18 Springer wells in row 1 have been drilled and drilling has begun in row 2. 9 of the 17 Springer wells are flowing back after stimulation and 8 are in various stages of completion. Early flowback rates are in line with our expectations for row 1, but we need a bit more time to get the wells lined out to provide an accurate summary of the results.

We currently have 14 rigs drilling in the SpringBoard with 8 targeting the Springer and 6 targeting the Woodford and Sycamore reservoirs. As expected, operating efficiencies continue to build and are translating to the bottom line from shorter cycle times, new steering technology, stimulation efficiency gains and growing infrastructure. 100% of our oil, gas and water are currently on pipe and 100% of our water is recycled.

The differential for our SpringBoard oil is the best in the company at just under $200 -- or $2 a barrel. We expect these efficiencies and our savings to grow as our operating -- operations team continue to make incredible improvements.

In summary, our third quarter was all about delivering the results promised, which sets up for -- sets us up for accelerated growth in the fourth quarter and on into 2019. With that, I'll turn it over to John.

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John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [5]

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Thank you, Jack. Good morning, everyone. The third quarter was strong with $314 million of net income, generating earnings per share ahead of Street consensus. Free cash flow generated from 2018 activity is also strong and is projected to approach $1 billion for the year. As such, debt is continuing to decline towards our ultimate goal of below $5 billion per 1x debt to EBITDAX. We anticipate achieving these targets in 2019, driven by further strong cash flow.

As of September 30, 2018, our net debt was $5.94 billion or roughly 1.5x debt to EBITDA. As of October 31, 2018, net debt is projected to be further reduced to approximately $5.7 billion after applying the proceeds derived from our minerals transaction with Franco-Nevada, as I will discuss momentarily. We are targeting for 2018 nearing debt of approximately $5.5 billion.

A higher level of CapEx was deployed in the third quarter than we anticipate in the fourth quarter. This higher level of CapEx was largely focused on completions activity as we took advantage of better summer weather to complete wells. We averaged 9 completion crews in the third quarter. For the fourth quarter, we expect to average 6 completion crews, a full third less. For the fourth quarter, we expect capital expenditures to range between $600 million and $700 million.

The benefit of our third quarter activity was seen late in the third quarter and will carry through the fourth quarter with a strong oil-focused 2018 exit rate entering into 2019. This production growth will generate a higher level of cash for the fourth quarter, driving further debt reduction. Across our broader guidance, we expect G&A, equity comp and DD&A to be towards the lower end or better on guidance. LOE is updated slightly to a range of $3.50 to $3.75 to reflect the volumetric impact on LOE of our enhanced focus on oil volumes.

Production annually and exit rate are solidly within our guidance, as Jack noted earlier. We estimate that 2018 CapEx includes approximately $650 million of capital with first production not until 2019. We expect our 2018 endeavors to set the stage for a strong 2019.

On October 23, we closed on our minerals venture with Franco-Nevada. As announced last quarter, Continental and Franco formed a new entity to acquire minerals, a majority of which are owned or operated leasehold and are planned drill schedule. At closing and reflected for purchase price adjustments, we received approximately $215 million for Franco's investment in our existing minerals portfolio.

Continental and Franco plan to invest an additional $375 million in minerals over the next 3 years, subject to achieving agreed-upon development thresholds. Continental's portion of the investment is $75 million or 20% of the total investment over the next 3 years to earn 25% to 50% of the revenues based on achieving predetermined targets. We anticipate achieving the full carry and realizing 50% of future revenues in the foreseeable future.

Further acquisition of minerals is ongoing. During the third quarter, we spent approximately $90 million on mineral acquisitions. During the fourth quarter, we project minerals activity totaling approximately $50 million or $40 million less than the third quarter. Recall, mineral acquisitions are included in Continental's CapEx and then we subsequently bill out Franco-Nevada with monthly capital calls. Thus minerals, along with completion activities, were the primary drivers of higher third quarter CapEx.

Although minerals revenue and volumes are not currently significant, we do expect strong growth in 2019. As an example, under Project SpringBoard, our minerals venture owns approximately 12% of the net mineral acres, an increase from 10% last quarter with an average royalty percentage of 18.75%. This will generate higher revenues and incremental returns for us in an area where significant development in multiple zones is ongoing. This simplifies our minerals strategy. We plan to use -- utilize our geologic knowledge and land expertise to acquire minerals in areas of future growth. Mineral ownership will enhance project economics and result in our prioritizing areas where we have successfully acquired minerals.

We see minerals as another avenue for the company to enhance shareholder returns, with the potential for a future IPO or to hold long term, generating another source of cash flow. The ultimate determination will be a value-based decision. It's nice to have options for a vehicle we expect to derive significant value from over the next few years.

In the third quarter, we saw strengthened oil differentials due to strong Gulf Coast pricing, strong seasonal demand and lower Cushing inventories, with our corporate oil differential at $3.72 and our corporate gas differential at a premium of $0.22. We remain well within our annual differentials guidance.

In the fourth quarter, we do expect to see higher oil differentials due to a heavy refinery maintenance season, the level of which is about double the norm for this time of year. Although we expect to see oil differentials to be wider for the fourth quarter, we retain our existing guidance -- annual guidance, although likely in the upper half of the guidance range.

The productivity of the Bakken is driving a significant expansion of basin takeaway. We expect to see the expansion of existing pipeline capacity as well as new pipelines entering the basin. Some of this capacity will come online in the next few months with the strong ramp-up through 2019 and entering 2020.

On the gas side, we expect fourth quarter gas differentials to remain strong and reiterate our annual guidance. Looking forward to 2019, we expect a significant expansion of gas processing capacity in the Bakken, expanding as much as 50%. We are actively updating our plans for 2019 and will issue formal guidance in early 2019.

We expect continued growth of oil volumes, strong cash flow generation and superior returns on capital employed. We will provide specific guidance on oil and gas volumes separately for 2019 to facilitate your understanding of our oil-weighted production growth. You should expect to see strong oil volume growth as well as a growing oil percentage in 2019. Our expectations for more detailed guidance is intended to provide greater transparency. We are well positioned, not only for 2019, but also the years that follow and look forward to providing you the details.

With that, we're ready to begin the Q&A session of the call, and I'll turn it back over to the operator for your questions. Thank you.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question comes from Drew Venker with Morgan Stanley.

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Andrew Elliot Venker, Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil and Gas Exploration and Production [2]

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I was hoping, John, you just gave some color on what you guys are thinking about higher level for 2019. If you could just give us any updated thoughts there as to how you want to set the capital program philosophically for '19? Whether that's a limitation on the upper end of growth or first achieving your debt targets and then maybe you look to return cash, just, kind of, how you're thinking about that.

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John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [3]

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I think, we're going to get to our debt targets in a fairly easy fashion. Getting there leaves a significant amount of cash flow to invest. I would expect a higher level of capital activity next year. We're obviously growing and continuing to grow on a larger base, so we're going to deploy more. But I think, cash flow, you're looking at numbers that are fairly similar to this year and of a significant nature. So we do clearly see getting below $5 billion next year and see it in a fairly reasonable time frame. You've heard us in previous quarters talk about and, I would say the same today, but we've talked about dividends. It tells you that if we're talking about these things, we're obviously expecting to generate a bunch -- a significant amount of cash flow. But we do not intend for that to impact the growth rate. We are a growth company. We expect to see strong growth in oil volumes.

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Andrew Elliot Venker, Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil and Gas Exploration and Production [4]

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Okay. And Harold, in your prepared remarks, you talked about being in this oil super cycle. Can you just give us your thoughts on, I guess, macro, for one, and how that relates to your hedging strategy?

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Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [5]

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Yes, it all comes back to supply and demand in the world. And we still see demand has grown about 1.5 million barrels to 1.8 million barrels of new oil. And on the supply side, hopefully, we can keep up with that. About 65% of that will come through the U.S., but if we go forward with Uranian sanctions, I anticipate another 800,000 barrels off the market, long term things are going to get tight. And so we expect it to be pretty close beyond -- going forward through the end of the year. So oil prices are going to be strong and hopefully, we'll have a cold winter to keep this away with natural gas.

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Andrew Elliot Venker, Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil and Gas Exploration and Production [6]

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And Harold, as it relates to your hedging strategy, does that mean just more, for the foreseeable future, no interest to add hedges?

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Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [7]

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Yes, I'm sorry, I didn't address that. We do anticipate we -- of course, we all hedge natural gas, as we have often and we have a program ongoing with that. But with oil, right now, we're going to remain unhedged.

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Operator [8]

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Our next question comes from Doug Leggate with Bank of America Merrill Lynch.

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Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [9]

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John, I wonder if I could take up on Harold's comment about offering a 5-year look at some point. I guess, at a high level, how should we think about how the companies redeploy just -- what's going to be looks like significant free cash? And I guess, what I'm really thinking about here is -- this is going to be a question for a company with your limited free float, obviously, because you can't buy back shares. So how do you think about how you communicate that, because, obviously, there's some concern, it seems that your capital program could end up and redeployed to other areas outside of the current core area such as the Permian? So any help you can provide, for example, 40% of the cash will -- would always go back to shareholders or something -- some commentary along those lines. Is that your intention or how could you help put some of those concerns to rest?

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John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [10]

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Sure, I'll try and address your question. There was a lot in there, so if I miss something, ping me back. Our 5-year plan and even beyond that, we have a view towards 10 years, is based on the existing inventory. There's no blue sky in our plans. It's based on primarily what you're seeing in the Bakken and in the south in Oklahoma and SCOOP and STACK. The New Mexico asset that you referred to is more in the exploration stage, so it's not really in our 5-year currently. As we go forward and as we get greater visibility on that, it's certainly something we can add. What that tells you is we have a very deep and rich inventory, not only in the Bakken, but also in SCOOP and STACK, and that we've got plenty of inventory to generate significant growth plans. We have a very clear view over the next 5 years that enables us to do a lot of long-term planning. I would expect capital deployment to be somewhat in the range that -- between the assets that we have now. We are going to be focused on oil -- on the crude oil side of it and the broader liquid side, so you'll see good growth there as well. In terms of a percentage of return of capital, that's something yet to be determined. We're going to hit our debt targets, so we're going to hit them fairly expediently. And then with that, we talked about dividends before. I don't think we're going to chase dividend yield. We'll put something in place that is reasonable and prudent and sustainable in a variety of crude oil price environment, so something that we could sustain in a lower market, and we'll go from there. As you look to debt, if you just go to our callable bonds, we could take that all the way down to $4.2 billion. So we've got a lot of room there and then that does position us well for dividends or to invest in other opportunities as we see them, for instance, if that's New Mexico or other things, we're always looking for opportunities.

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Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [11]

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And there we're probably, all day, looking at stock buyback as deep as it is today.

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Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [12]

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Well, it kind of begs -- leads me to my second question, if I may, and this is really more -- or Jack, you know it's coming here, but your stock is down 30% from the top. Obviously, you can't buy back your shares. But I think, there's still -- despite your incremental disclosure, I guess, this morning, there's still some questions, I think, over what that inventory debts looks like. And Jack, what I'm referring to is when you give a rate of return guide, obviously, that's a great number to show the market. But it has inputs and outputs, meaning that smaller wells have smaller capital costs, for example. So when you talk about the 4,000 location inventory in the Bakken, can you help us understand, what proportion of that would you characterize as, like, say, the 1.2 million type curve or better? And how do you think about the average over that range? And I'll leave it there. I've got another one, but I'll leave it for someone else.

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Jack H. Stark, Continental Resources, Inc. - President [13]

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Sure, Doug. What I would say is that this Bakken inventory that we talk about is not, say, high-graded, this 10-year inventory we're talking about is not high-graded to just the 1.2 area. There's areas out there where we're seeing a bit less rate EUR, but we're also, as you said, seeing less cost. And we're continuing to push this envelope, but also think about it vertically. We're also seeing various degrees of EUR vertically as well from the middle Bakken to the Three Forks to the Three Forks 2, as I mentioned. So within units, you have variation in the average EUR per well. But what we've provided here, what we're trying to do when we do give you this rate of return is try to give you that blended perspective of the quality of that, because we have a huge footprint in this Bakken with our leasehold position of 800,000 acres out here. And so we're drilling in broad and wide, quite diverse areas and continuing to expand that. And our teams have type curves all across this field and we'll -- as time goes on, we're going to be able to provide you more clarity on what some of this inventory looks like, as we continue to expand this play. But I mean, right now, I think, quite frankly, the -- giving you a rate of return of 80% to 100% shows extremely good capital efficiency that we are able to derive from our assets up here in the Bakken, and, I think, as an investor, should really get great comfort with that. And it is in and when we pull out -- when we talk about our, kind of, 5-year look on what we believe our 5-year plan here as we get around to the first year, we talk about that a bit. I think, you'll get comfort level in just how strong the Bakken is as a part of that growth.

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Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [14]

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Yes and don't forget the wells that's above that 1.2, today's recommended average. So there's a lot of wells where we have 2 million barrels EUR.

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Jack H. Stark, Continental Resources, Inc. - President [15]

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Yes, we've got wells out there, as you know, with individual zones where you get in excess of 1.2 and you get some below and that's -- the 1.2 is our average.

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John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [16]

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Doug, remember, we're one of the few companies that guide on return on capital employed. We've also indicated that we expect that to be increasing next year. It will be part of our guidance for next year. I would expect a higher range than what we've had in '18, as it's continuing to improve. That's driven by the Bakken and the strong returns that you're seeing in the South as well. And we'll follow up -- you said you had another question, we'll follow up with you on that.

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Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [17]

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I'll take that off-line, John, but I appreciate the 5-year guide -- guidance. I think, everybody listening in would really appreciate when you come out with that. So thanks for considering and I'll see you in a couple of weeks.

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Operator [18]

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Our next question comes from Arun Jayaram with JP Morgan.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [19]

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Just some thoughts, John, as you think about some of the near-term Bakken diffs. How do you think the diffs could play out over the next 2 to 3 quarters?

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John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [20]

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We actually expected some of those questions, so we brought Ramiro Rangel and Josh Baskett, the heads of our marketing department in, and we're going to let them speak up on some of that today. Thank you for the question.

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Ramiro F. Rangel, Continental Resources, Inc. - SVP of Marketing & HR [21]

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This is Ramiro Rangel. Through the third quarter, we had record diffs, and they were really attractive. What happened is there were significant pad to refinery turnarounds in October that, coupled with seasonal demand softening, ended up in differentials weakening. But we expect that to get better in the fourth quarter that we feel that there's going to be -- capacity is going to be built. So longer term, we feel that we're in pretty good shape.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [22]

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Could you maybe quantify kind of your thoughts on how the diffs could play out a little bit more?

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Ramiro F. Rangel, Continental Resources, Inc. - SVP of Marketing & HR [23]

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Sure. I think a lot of it is going to be tied to future capacity. And we feel that there's probably going to be about 700,000 to 1 million barrels per day of additional pipeline capacity. And we feel that as that comes on, Arun, that the differentials will start to improve. And so we would feel that, that's going to be one of the biggest keys. And then for us, with us being the largest producer in the Bakken, we have significant leverage and options and flexibility that really allow us to be able to manage our portfolio and optimize our netbacks. So we feel that we're in better position than most. But the bottom line is that we feel that the midstream companies that are out there have enough proposed pipeline projects that are going to allow differentials to come back in. So I think that's the key.

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John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [24]

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A little bit of a different color. Recall that in the south in SCOOP and STACK, we're looking at a sub-$2 oil differential so very attractive that we're continuing to see that strength there. And recall that I also indicated in the call that we are retaining our existing guidance for the year. The guidance is $3.50 to $4.50 corporate-wide for the full year. We did indicate we expect it to probably see it in the upper half so that's signaling some up in the fourth quarter. You could see $1 or $2, a couple of bucks higher in the fourth quarter. But as Ramiro indicated also, as we're coming out of refinery turnaround, we're starting to see some improvement there. So it's a little bit of a moving target. But I think we're well positioned and these things tend to pass. The key is there's a lot of infrastructure coming into the Bakken and there's a lot of long-term capacity there.

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Jack H. Stark, Continental Resources, Inc. - President [25]

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Yes, Arun, I just think I'd just add in there too that about 50% of our volumes up in the Bakken are on firm commitments there. And then those firm commitments are, I mean, I think we're probably within the sub-$4 on all of those barrels. And so that really helps offset any kind of say widening we might see in the differentials here in the fourth quarter.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [26]

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Great, great. Jack, any initial observations on row 1 of the Springer program? How are the initial wells? It looks like they're meeting your expectations, but just any initial observations would be helpful?

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Jack H. Stark, Continental Resources, Inc. - President [27]

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It's really where we're at right now. They're just very early in the flowbacks right now. And we've got 9 flowing back and another 8 are in various stages of completion. So what we'd really like to do is get these wells on and be able to give a broader, better perspective as opposed to just a couple of single wells, give a perspective on just what kind of results we're seeing across row 1. So unfortunately, it's just a bit early for us to be able to do that. The wells are still cleaning up. We really thought we might be able to do have some results to talk about. I mean, I'd love to have some right now, but we're just not quite there. But as we do get these results, we've talked about between now and year-end possibly having a web -- some sort of a webinar perhaps to discuss the results. We'll just see. But right now, the -- we've got to just continue to be patient and allow these wells to clean up and then we'll have more to talk about.

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Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [28]

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Fair enough. Look forward to that 5-year guide.

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Jack H. Stark, Continental Resources, Inc. - President [29]

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And I will tell you that it's a lot, what else come off that. I mean, no problem and they're starting out nicely.

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Operator [30]

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Our next question comes from Jeanine Wai with Barclays.

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Jeanine Wai, Barclays Bank PLC, Research Division - Research Analyst [31]

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In terms of the SCOOP, I was just wondering if we could get a little bit more color there on your near-term activity plans? I think you currently have the 14 rigs allocated to Project SpringBoard. But you reported that you would total a 16 rigs in the SCOOP overall and you're ramping to 18 by year-end. So we're just wondering what the non-Project SpringBoard rigs are doing? And how does the oil capital efficiency or whatever those rigs are doing compare to the Bakken and the SpringBoard?

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Patrick W. Bent, Continental Resources, Inc. - SVP of Drilling [32]

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This is Pat Bent and that is correct, we'll exit with 18. The other rigs outside of those 14, we have 1 in merged and then we'll deploy another 3 by year-end on Woodford oil. And so we'll keep our oil focus high throughout the end of the year.

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Jeanine Wai, Barclays Bank PLC, Research Division - Research Analyst [33]

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Okay, great. And then sticking back to some of the CapEx points. You mentioned deploying more capital next year. And I think the old commentary was for $2.5 billion to $2.8 billion for 2019. So how should we view the $600 million of CapEx this year that won't really produce until next year? Is it more of a credit towards 2019? Or it sounds like you're pushing forward a larger program. We're just trying to frame kind of free cash flow and what's available for the dividend.

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John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [34]

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Well, free cash flow -- we'll have plenty for the dividend. The free cash flow that we're looking at is something that's in the comparable type range than what we've had in what we're projecting in 2018. That could move some, but I think if you compare us to the industry, we are very much in the significant category in terms of cash flow generation versus peers. So I would expect that to continue. Stronger oil prices, obviously, enable us to do a little more, while still generating net cash flow. So we'll probably be looking at a higher level of CapEx. But it'll be in a reasonable range and it will still allow us to generate that strong amount of cash flow. We're not altering that in any form or fashion.

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Operator [35]

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Our next question comes from Derrick Whitfield with Stifel.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [36]

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Building on Arun's Bakken takeaway questions, what's the timing for incremental pipeline capacity in the Bakken? And to what degree could rail offer near-term incremental capacity?

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Josh Baskett, Continental Resources, Inc. - VP of Oil & Gas Marketing [37]

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Sure, this is Josh Baskett. So we see some fairly substantial opportunities coming our way early 2019 and then throughout the entire year. We're under CA on several of these opportunities so we can't really throw out the figures, but we definitely see some relief coming very soon. As far as the rail capacity, right now, we're at about 270,000 barrels a day, and we believe we can get over 300,000. We're also looking into the possibility of converting some of the older railcars for the new standards.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [38]

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Great. And then maybe moving over to the STACK. When you think back to your Q4 '17 disclosures on full field development concepts, has incremental data since then in any way biased your thoughts around optimal spacing for future units? And where I'm specifically speaking to is the outperformance of the 3 units you guys just announced and the comments that you have on Page 14, which indicate Simba's results will help you define development model for the STACK condensate window.

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Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [39]

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Yes, this is Gary Gould. And yes, we're very proud of our teams for the results that we're seeing from our STACK units. All 3 of them just give us really strong results for these 6 wells. I think it's important to note that whether we optimize with 6 wells or with 8 wells, it's going to depend on what the geology is across the field. Some areas have more original oil in place or more condensate in place, and so in some places, we may develop with 8 wells and another may be 6 wells. In other words, 3 to 4 wells per zone. But as you can see from what we show on Page 13, the results, that include record results this quarter, show that we're getting almost the same PV-10 from 6 wells this quarter as we had forecast for 8 wells. So very good results this quarter.

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Jack H. Stark, Continental Resources, Inc. - President [40]

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Yes, I would say, I just -- I can't help but add there, just the team has done a great job studying this. And the results that we're seeing here did really confirm our model. I mean, and bottom line is that and it is obviously going help us as we continue to develop the 65 units we've got yet to develop in the play.

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Operator [41]

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Our next question comes from Bob Morris with Citi.

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Robert S Morris, Citigroup Inc, Research Division - MD and Senior U.S. Oil and Gas Exploration and Production Analyst [42]

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Jack, nice results in the STACK oil window. On Slide 13, just continuing with that, you showed it for the 6-well units, the uptick to $100 million in PV, but you're still using the total unit EUR of 8 million barrels, which implies 1,333 MBoe per well. But that uplift from the Jalou and the Homsey on the orange part of that bar seems to reflect the outperformance or an even higher EUR. So my first question is in that orange bar uptick, what is the assumed EUR to get to that $100 million PV-10 now?

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Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [43]

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Yes, this is Gary Gould. And that's incremental value reflected in that orange bar. You're right, we kept EUR the same. It's just early on the flowbacks so we clearly see higher IPs, and we expect the EURs could very easily increase as we go forward. But for now, we held the EURs the same, but we did raise the IPs consistent with what you see on the previous page, and that's how we got the higher value.

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Robert S Morris, Citigroup Inc, Research Division - MD and Senior U.S. Oil and Gas Exploration and Production Analyst [44]

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Okay. So that just essentially assumes acceleration of the same reserves and getting that higher value. So my second question is the factors that drove the outperformance in those wells, which are very good at Jalou and Homsey. How many of those factors translate to, if you were drilling 8 wells per section, would you expect to see similar type outperformance on 8-well units from what drilling outperformance on the 6-well units that then move up that valuation too?

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Jack H. Stark, Continental Resources, Inc. - President [45]

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Well, it really comes down to the oil in place and placing the proper number of wells in each of these units based on those estimates. And so the performance in these units is demonstrating to me that the teams had identified and figured out what would be the proper well density and well spacing in these units. And so each of these units, as we go through them, as Gary said, we're looking at 4 to 6 wells per zone is what we anticipate will typically could in each of these reservoirs. And we expect to have, on average, about 2 wells per zone. So that can mean 6 to 8 wells typically per unit. And with that, we think that gives us the optimum economics for unit development.

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Robert S Morris, Citigroup Inc, Research Division - MD and Senior U.S. Oil and Gas Exploration and Production Analyst [46]

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Sure. I guess that was just with the outperformance in the future, if you drill 8-well units is there an orange bar than to be put on top of the green bar in the future on what is the 8-well units?

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Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [47]

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This is Gary Gould. And that's a possibility. We will continue to evaluate the results that we've seen today. We've got several different density tests that we've got in the ground now, and with the strongest results most recently, we'll continue to optimize as we move forward.

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Jack H. Stark, Continental Resources, Inc. - President [48]

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Yes, if we duplicate these results with 8 wells, we're definitely going to see that 8 bar -- that present value from 8 wells climb, no doubt.

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Robert S Morris, Citigroup Inc, Research Division - MD and Senior U.S. Oil and Gas Exploration and Production Analyst [49]

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Yes, actually that's what I'm looking for.

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Operator [50]

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Our next question comes from Brian Singer with Goldman Sachs.

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Brian Arthur Singer, Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst [51]

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Can you talk a bit more about how the positive results you're seeing in the Bakken impacts your willingness to allocate increased capital activity on a relative basis, i.e., do you see yourself shifting a bit more on a percentage basis towards the Bakken going forward? And then as more of a follow-up to Doug's question earlier. We look at Slide 8, where the majority of the wells that have been drilled where that you're highlighting here are within a 30- by 40-mile box. When would you expect to see any geographical shifts away from that box and what impact on productivity would be expected?

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John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [52]

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So on the first part of the capital allocation, the good part of that is we're blessed with a deep oil-rich inventory in the North and South. Percentages may vary a little bit from one to the other depending on the timing or development plans in a given area. But when you look at Project SpringBoard in the South, it competes very favorably with the strong Bakken results. So the -- we do have some geographic opportunity. And we have geographic opportunity within basin, also just because of the size and scale of our position. So it's not uncommon you'll see some moving around. We're still working through some of our plans for next year, finalizing some of those. I would say, for now the allocation between the Bakken and SCOOP and STACK is relatively consistent. So and the second part...

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Jack H. Stark, Continental Resources, Inc. - President [53]

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The second part here, Brian, looking specifically at Page 9, you're looking at...

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Brian Arthur Singer, Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst [54]

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On page 8, I'm sorry to interrupt. You've got that 30- by 40-mile box, right, where the majority of the well are, and I just wondered how -- what the inventory is within the box relative to outside the box and when there would be a disproportionate shift away from that.

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Jack H. Stark, Continental Resources, Inc. - President [55]

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Oh, I don't have that just off the top of my head right now what the inventory would be and within that given area. But what I can tell you is if you look at Page 9, you can't just look at our results, you got to look at everyone's results across the play to get -- really appreciate what's happened in the Bakken as a result of basically previously understimulating these wells. And this trend continues to expand. And at this point, I mean, there's wells that obviously aren't -- the results aren't shown here yet, but are testing substantially further North and South. And so I think you'll -- so the results will be forthcoming in those areas as well. So -- but specifically for the inventory right in that particular box, I don't have that right now. We'll talk to you later, maybe.

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Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [56]

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You can say some of the wells that Jack talking about is definitely out of that 30- to 40-mile box already.

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Jack H. Stark, Continental Resources, Inc. - President [57]

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We've often talked about you see wells up there close to Divide County. They're at -- performing at the 1.2 MBoe equivalent model. So anyway, I think just again this is an expanding play through technology.

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Brian Arthur Singer, Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst [58]

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Great. And then you mentioned might have been John mentioned in the comments that you had 9 crews running in the third quarter and that's going down to 6 in the fourth quarter. Can you talk about what is more of a normalized rate or as you think about -- broadly as you think about '19 or I guess, to what degree that moving from 9 to 6 is a function of timing and capital allocation versus efficiency, efficiency gains?

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Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [59]

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This is Gary Gould. Moving from 9 to 6 is based on having moved our completion inventory to first production. During the summer months, we had a lot more activity, especially in North Dakota when we have those long hours of sunlight, and we picked up some frac crews and our DUC count well down, so that by the end of this year, we're going to be at just normal operating counts when it comes to wells that are drilled but not yet completed.

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Operator [60]

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Our next question comes from Ryan Todd with Simmons Energy.

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Ryan M. Todd, Simmons & Company International, Research Division - MD, Head of Exploration & Production Research and Senior Research Analyst [61]

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Maybe if I could follow up with one on the Bakken. You're running 8 rigs at present, which is a little ahead of our expectations at this point. Obviously, a lot of completions taking place in the fourth quarter. How should we think about trajectory there into 2019, maybe both in terms of rig count and cadence of completions?

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Jack H. Stark, Continental Resources, Inc. - President [62]

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We are rigging up to have more activity and growth in the North. And so as mentioned earlier, we're going to be a normal well count as far as just standard operations. But then as we move forward and get more of these wells drilled, and we'll be picking up more completion crews, and this will be a driver for how Continental stays oil-weighted for the next several years.

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Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [63]

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That must be rig count for 2019.

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Ryan M. Todd, Simmons & Company International, Research Division - MD, Head of Exploration & Production Research and Senior Research Analyst [64]

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Sorry. Is 8 rigs a good assumption to think about for 2019 in the Bakken? Or will we likely see that go away?

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Jack H. Stark, Continental Resources, Inc. - President [65]

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Well, we really haven't come out with our plan for '19 obviously, but we do anticipate some additional rigs being added in '19. We've added these rigs, like you said, we're ahead of schedule here. We expected it be about at 8 at year-end. We're already there. And that's just basically us getting prepared for continued growth into '19. And so you will see some additional rigs coming in to the play in '19. We'll get more details on that as we get out our '19 plan.

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Patrick W. Bent, Continental Resources, Inc. - SVP of Drilling [66]

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And this is Pat Bent again. And like we'd indicated, we'll exit '18 with 8 rigs in the Bakken. I just want to mention that our rig acquisition activity is very opportunistic going into '19. And so we don't need to pick up every rig we see come by and so we have the opportunity to be a fairly selective in any incremental rig activity going into '19.

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Ryan M. Todd, Simmons & Company International, Research Division - MD, Head of Exploration & Production Research and Senior Research Analyst [67]

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And then maybe one follow-up on an earlier conversation on cash priorities in terms of use of cash. I appreciate the -- some of the discussion about the dividend. What would you need to see -- I know you're considering the dividend. What would you need to see the kind of -- to make that happen? Is it a question of you need to get the debt down to that $5 billion target first? Do you -- is it a combination of kind of confidence in the commodity and operational kind of critical mass? How should we think about what you would need to see the kind of -- to kick that off?

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Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [68]

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Yes, you're exactly right, Ryan. We intend to get debt down to $5 billion and consider the dividend. And look ahead and as far as oil prices and supply and demand certainly will be a factor in that.

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Ryan M. Todd, Simmons & Company International, Research Division - MD, Head of Exploration & Production Research and Senior Research Analyst [69]

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Okay. So I guess you need to hit the debt target first before you can...

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Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [70]

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That's correct. Yes, that's correct.

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Operator [71]

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Our next question comes from Brad Heffern with RBC Capital Markets.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [72]

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Just going back to some of the STACK spacing questions from earlier in the call. I was just wondering if you could give an update on what the STACK inventory number is? Is it just the 65 units you mentioned times 6 to 8 wells per section? Or is there a different way we should be thinking about that?

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Tony Barrett, Continental Resources, Inc. - VP of Exploration [73]

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Brad, this is Tony Barrett. So when you -- the inventory, the 65 units was pretty much split evenly between the oil and the condensate windows. Of course, we have a really large acreage position in the gas window, which is about double, the condensate we're talking about in the oil and condensate window. So stepping forward, the way we look at it is these 65 units over the coming years will be developed with 5 to 6 to 8 wells per section -- incremental wells per section as we step forward in fully developing STACK.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [74]

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Okay, got it. And then, I guess, on the NGL front, can you talk about how much of your corporate-wide volumes go to Mont Belvieu and any contracts you have for fractionation there?

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Jack H. Stark, Continental Resources, Inc. - President [75]

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Sure. The -- out of the Bakken, a lot of our NGLs are priced out of Conway. But in Oklahoma, the preponderant, 85% to 90% is priced off of Mont Belvieu. And we do see a lot of fractionation being built. We feel that in 2018, about an additional 100,000 barrels per day is going to be built of new frac. In 2019, about 300,000 and about -- 2020, about another 500,000. So you're seeing a lot of new capacity that's going to be built in Mont Belvieu, which should really help the industry a lot.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [76]

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Okay. There are no concerns about any constraints on fractionation capacity before that comes online?

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Jack H. Stark, Continental Resources, Inc. - President [77]

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It's going to be sporadic for some producers. Our agreements are very attractive to us, so we haven't seen that really impact us. But the industry is responding really well in being able the fractionation that's needed.

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Operator [78]

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Our next question comes from Subash Chandra with Guggenheim.

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Subhasish Chandra, Guggenheim Securities, LLC, Research Division - MD and Senior Equity Analyst [79]

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Just back to the Bakken oil question. I guess, with the takeaway of 700,000 to 1 million barrels for the basin you're anticipating, do you also anticipate any change in your oil flows, Gulf Coast versus Cushing versus East or West Coast?

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Josh Baskett, Continental Resources, Inc. - VP of Oil & Gas Marketing [80]

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Sure. This is Josh Baskett again. We are currently evaluating several new projects. And we believe ultimately that the Gulf Coast will be where the majority of the growth barrel will show up. Again, we're under confidentiality so we can't share to any details there, but we certainly believe that's the future for the Bakken barrel.

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Jack H. Stark, Continental Resources, Inc. - President [81]

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And then we're always working to get advantaged markets and looking for the best price. So you can rest assured that's the focus and intent of our activities.

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Subhasish Chandra, Guggenheim Securities, LLC, Research Division - MD and Senior Equity Analyst [82]

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Yes, sure. I was just -- from an urgency perspective because it looks like at least basin production is up against current pipeline constraints. And I guess, the state is calling and anticipating a lot more growth. In terms of timing, is there any way to be more specific about how you see these projects coming on? Are they sort of a year or 2-year lags or do you anticipate anything quicker than that?

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Josh Baskett, Continental Resources, Inc. - VP of Oil & Gas Marketing [83]

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We believe by January, we'll see some expansions of capacity -- pipeline capacity. We also see some expansions coming maybe midyear and then a big slug towards the end of the year. So it's again, it's coming fairly soon.

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Subhasish Chandra, Guggenheim Securities, LLC, Research Division - MD and Senior Equity Analyst [84]

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Okay, terrific. And just as a follow-up. The SpringBoard guidance you'd given earlier, I think it was 10,000 barrels a day of oil for maybe the fourth quarter, something like that. And that was given before any of these rows were drilled to flowing back. Do you anticipate to fine tune that to reappraise that? Or should we run with that for the time being?

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Jack H. Stark, Continental Resources, Inc. - President [85]

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I think that's a safe number to go with, Subash, right now. I mean, we'll get some results here, but what we put out there was that we expect that it could add as much as 10% to our oil volumes over the next 12 months, and I think that was from last quarter to just provide some perspective. And so we have no problems sticking with that number.

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Operator [86]

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Our next question comes from Neal Dingmann with SunTrust.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [87]

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Jack, maybe question for you or Gary, a couple have asked about the Slide 13, but I always like that slide of yours. Looking at sort of the optimal, the 6 to 8, are there variables such as if you're able to pick up the minerals under there or some well cost go down further or more efficiencies that you could see change that max economic, that well count would maybe even go up more as far as downspacing and all, especially if you're able to add minerals under there?

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Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [88]

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Yes, this is Gary Gould. And we're always looking to optimize. The biggest drivers are always price and production, but the second driver is always CapEx, and we continue to optimize right now. On the completion side, we're looking at savings of between $100,000 and $500,000 per well. The savings is really being driven by stage efficiencies as well as lower proppant costs.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [89]

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Got it. And then just my last follow-up -- go ahead guys. I'm sorry.

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Jack H. Stark, Continental Resources, Inc. - President [90]

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I was just going to say that John had mentioned that we have about 12% of minerals underneath Project SpringBoard. But if you look at specifically underneath our leasehold, it's not going to drill about 17%. And so that really starts showing how the value of these minerals are really going to hit the bottom line here because in those units, we end up with 100% net revenue.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [91]

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Great point. That's exactly what I was after there, Jack. And then just lastly on service cost. One, it sounds like as you continue to use obviously been the most active operator in the Bakken, are you seeing yourselves -- I've heard some others not as much in the Bakken, do longer-term deals. I've heard of a few deals out there where some other folks are locking in 3-year deals. I guess, that's kind of my first question as far as would you lock in some other things. And then just curious on I know Harold gave a supply-demand picture. Just again being the service expert, wonder what Harold thinks about the service cost sort of at this level?

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Patrick W. Bent, Continental Resources, Inc. - SVP of Drilling [92]

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Yes, real quickly, this is Pat Bent. And on the rig activity again, we've been fairly opportunistic and been selective. And so we don't see entering into any longer-term contracts a year or less as what we're currently at and where we intend to stay through '18 and into '19.

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Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [93]

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Yes, by perspective long term on service costs are that what these companies really need -- needed was utilization. And now we're seeing that across the industry. A lot of them are commit fully utilized. And we still see a lot of expansion within our industry today. That's what's going on when you look broadly. So these service companies are getting more healthy all time. And so instead of this portion prices up continually getting more efficient and with more utilization, we think it could stay in about the same as they stand today.

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Operator [94]

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Our next question comes from Daniel Ashley with Wells Fargo.

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Nitin Kumar, Wells Fargo Securities, LLC, Research Division - Senior Analyst [95]

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Actually this is Nitin Kumar from Wells Fargo. Just maybe one question. One of the comments you made is about $650 million of the capital this year was spent for 2019. I'm thinking of average cost around $10 million or so per well, that suggests you would have a DUC inventory or not even in DUC inventory, but a completed well inventory of around 60 wells. As I think about the longer term, is that a fair pace for the level of activity you're contemplating in the 5-year plan?

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John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [96]

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Recall that $650 million, it can be -- the wells associated with can be in various stages, some could be drilling, some could be in completion, some could be in a DUC inventory. So unfortunately, it's not as easy as to calculate. I don't have the projected DUC count at year-end. That's partially at hand. That's partially because as what Gary said, we're projecting to be at normal levels, we're pretty much at normal levels today. So I think you'll see us at normal levels. It's not uncommon that we have a significant amount of capital. For instance, everybody's asked about the third quarter. We spent a lot of capital in the third quarter completing wells. We're getting the production this quarter. we're spending some capital now and will get another slug of production in '19. So that's just a normal cadence and pace. And recall, everything we do on the Bakken is on large pads and in the south, it's more and more pads today than certainly compared to 2 or 3 years ago. So that gives you a little more lumpiness on timing and it can give you some variability quarter-to-quarter on capital. But we feel good about where we're at.

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Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [97]

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This is Gary Gould, and right now, we're projecting that we'll have about 120 wells in the north to be drilled but not yet on first production and about 33 in the South. And that's a total of about 150 and that's about 50 less for this year. And again, we think that's just normal operations going forward.

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Nitin Kumar, Wells Fargo Securities, LLC, Research Division - Senior Analyst [98]

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Great. Maybe just talking about that lumpiness. You talked about, I think, 60% of your Bakken wells in the third quarter were toward the latter part of the quarter. Can you -- do you have an estimate on maybe what the cadence is for 70 wells that you're planning to complete in the Bakken this quarter?

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Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [99]

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This is Gary Gould. And it's evenly weighted to maybe a little bit earlier. We definitely have a lot of confidence in where we're going as far as production goes. So we're going to be getting those wells on maybe a little earlier than the midpoint of this quarter.

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Jack H. Stark, Continental Resources, Inc. - President [100]

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And then on the 70 wells, some of them were completed at the end of the quarter. They're coming online in the fourth quarter. So what we're trying to convey there, there's a lot of new fresh production coming from initial well results.

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Nitin Kumar, Wells Fargo Securities, LLC, Research Division - Senior Analyst [101]

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Perfect. If I could just sneak one in. You talked about increasing activity. Maybe directionally, as you talk about free cash flow and dividends, so what is the price that you are willing to consider for your budgeting exercise for '19?

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John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [102]

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Commodity price?

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Nitin Kumar, Wells Fargo Securities, LLC, Research Division - Senior Analyst [103]

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Yes.

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John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [104]

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Well, I mean, commodities move. We generally are starting what's kind of a $60, $65 price, but then we're running some areas across a wide range of prices to stress test in some cases, not because it's our expectation but we stress the model and evaluate different scenarios it could play out and that type of thing. But we're in the -- utilizing that. I expect that commodity prices next year, oil prices will probably be higher than that, but I think it's a good base to start with. And then we work those -- look at every $5 increment from there.

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Operator [105]

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Our next question comes from Matt Portillo with TPH.

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Matthew Portillo, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - MD of Exploration and Production Research [106]

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Just a follow-up on, I apologize for the third question on rail capacity, I mean, on transportation capacity, but it obviously paints a pretty bullish picture for bases differentials going forward. I was wondering if there's any color you might be able to provide on of that 700,000 to 1 million barrels of takeaway? How much of that would potentially be brownfield versus new greenfield projects? And if there's any high-level color you might be able to provide in terms of kind of the capacity add that might be weighted towards 2019 versus 2020-plus?

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Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [107]

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Well, first of all, if you look at the DAPL, it decides that line, do we know that you've got expansion capabilities there that it's going to be almost a 40% more capacity. There's no come on with that eventually. That was from their initial projection to where that's going to go. So that's a good bit of capacity right there that we're adding. And then next is new construction. Obviously, like as Jack pointed out, there's a lot more oil to come out of the Bakken. And so these new pipeline projects are going to pay off beautifully as time goes on. So there's going to be a lot of brownfield-greenfield type to be added.

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Jack H. Stark, Continental Resources, Inc. - President [108]

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And that's exactly right, yes. And you will see some projects where you're going to be able to add compression. And those are pretty easy and so you'll see those coming online. But we do expect that greenfield projects to be able to come on as well a little bit later on in the cycle. So it's a combination of both.

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Operator [109]

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Our next question comes from Marshall Carver with Heikkinen Energy Advisors.

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Marshall Hampton Carver, Heikkinen Energy Advisors, LLC - Founding Partner and Director of Research [110]

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Just a couple of quick ones. The average working interest has been bouncing around each quarter in the Bakken. About how many net wells would the 70 gross wells be for this quarter?

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John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [111]

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Just a second. We're pulling that up. Why don't you go to your question, while we're looking for that and then we'll come back to that?

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Marshall Hampton Carver, Heikkinen Energy Advisors, LLC - Founding Partner and Director of Research [112]

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Okay. The Springer wells, the wells that are completing now, the wells be online any day now or more late in the quarter or how should we think about that?

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Jack H. Stark, Continental Resources, Inc. - President [113]

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Yes, they're all in various stages of flowback right now. Obviously, the ones on the East side have been on a little bit longer than the ones on the West side are just getting turned on. So it's row development and there's row flowback and so it's quite an operation out there. And so that's the status right now.

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Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [114]

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They're getting close on the number.

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Marshall Hampton Carver, Heikkinen Energy Advisors, LLC - Founding Partner and Director of Research [115]

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Okay. I guess, I could ask another one, while they're doing that. The Bakken was kind of...

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John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [116]

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It's about a 60% to 65% working interest, on average on that.

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Operator [117]

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Ladies and gentlemen, thank you for participating in today's question-and-answer portion of today's call. I would now like to turn the call back over to management for any closing remarks.

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Rory R. Sabino, Continental Resources, Inc. - VP of IR [118]

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Thank you very much for your time today. Please reach out to the IR team if you have any further questions and look forward to hear from you.

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Operator [119]

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