Continental Resources, Inc. (CLR) Q3 2018 Earnings Conference Call Transcript

Continental Resources, Inc. (CLR)
Q3 2018 Earnings Conference Call
Oct. 30, 2018, 12:00 p.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Good day, ladies and gentlemen, and welcome to the Q3 2018 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, and instructions will follow at that time. If anyone should require assistance during the conference, please press * then 0 on your touchtone telephone. 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.

Rory Sabino -- Vice President of Investor Relations

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 Baskett, 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 $70.00 per barrel WTI and $3.00 per Mcf natural gas.

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 that, I will turn the call over to Mr. Hamm. Harold?

Harold Hamm -- Chairman and Chief Executive Officer

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 prices for crude oil, averaging nearly $70.00 WTI for the quarter and nice natural gas prices above the normal range, validating our decision to remain unhedged with our crude oil and to curtail our natural gas production in the second quarter until the market recovered. Along with record production from the Bakken delivered by Continental teams, net income for the quarter was $314 million, beating consensus.

The results of the third quarter began to show the benefits of our decision earlier this year to shift 95% of drilling activity to our crude oil development projects. In all three 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 among select oil-weighted peers and delivering on our promise to bring on a 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 to drill and complete wells, setting up the third and fourth quarters, as well as 2018, to reflect new oil-weighted growth.

If you will recall, last quarter, we talked also about our rational for shifting our focus to oil and accelerating our growth into yearend, having recognized an opportunity in the market. While we remain a highly disciplined company with a primary focus on capital, efficient growth, and corporate returns, it was 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 benefits from horizontal drilling of large-scale resort plays such as the Bakken that I've witnessed during my 50 years-plus as an excavationist 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 enables 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 grander update now to our five-year plan, and we will discuss portions of this plan when we give 2019 guidance in early 2019. What I love about this plan is that it's all about the inventory 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. But I want to say thank you to the Continental team, which originated this unique minerals model and have worked very hard to make the close; and the Franco 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 by infrastructure, and Middle East tensions are further elevated by some recent events. Thankfully, the narrative on oil supply can be turned to the positive developments in the U.S., as 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 has truly proven to be a breakout year for Continental. Stronger commodity prices rewarding our nonhedge-able position, allowing full oil price upside participation for our shareholders and driving free cash flow approaching one billion dollars for the entire year. The timing of the plan 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 dividends, 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 under way in America.

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

Jack Stark -- President

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 second 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 yearend, 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 was driven by two things. First, 60% of the third quarter Bakken completions 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 on 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 two-stream reporter. If we were to report on a three-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. Results were in line with expectations, and two of the wells made our top 10 list of Bakken producers based on first 30-day average rates. We currently have eight rigs drilling in the Bakken, which is up two from the second quarter, as we prepare for continued growth into 2019.

As many of you know, Continental is the 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 three 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 that 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 a half a billion barrels of oil per year at today's rates.

My second point is that Continental's technical teams now estimate that 30 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 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 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, higher rates of return, and overall consistency and quality of the oil.

Now, speaking specifically about Continental, there are two keys 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 nine 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. This is 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 $65.00 oil and $3.00 gas. Bottom line, the Bakken will be a key driver for Continental's oil growth for years to come.

Now let's move to STACK, where we recently turned three fully developed Meramec units to production. These three 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 in the over-pressured window of STACK. The three units flowed at in impressive combined initial rate of just over 74,000 BOE per day from 18 two-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 three Meramec units include the Jalou and Homsey units in the over-pressured oil window, and the Simba unit in the over-pressured condensate window. All three units were developed with a total of six two-mile equivalent wells placed in both the upper and lower Meramec reservoirs. The Jalou unit's 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 rights, the Jalou wells also set an industry rate record for wells completed and fully developed units in the over-pressured 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, or the production being oil. The Homsey wells are outperforming our 1.2 million type curve, million BOE type curve, by approximately 15%. And 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 optimum unit development in the over-pressured Meramec condensate window going forward.

The performance of these three 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 over-pressured 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. Nine of the 17 Springer wells are floating back after stimulation, and eight are in various stages of completion. Early fallback 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 eight targeting the Springer and six 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 $2.00 a barrel. We expect these efficiencies and our savings to grow as our operations team continues to make incredible improvements.

In summary, our third quarter was all about delivering the results promised, which sets us up for accelerated growth in the fourth quarter and on into 2019.

With that, I'll turn it over to John.

John Hart -- Chief Financial Officer

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 toward our ultimate goal of below $5 billion, or 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 yearend debt of approximately $5.5 billion.

A higher level of capex was deployed in the third quarter than we anticipated 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 nine completion crews in the third quarter. For the fourth quarter, we expect to average six completion crews, a full third less. For the fourth quarter, we expect capital expenditures to range between $600 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 toward the lower end or better on guidance. LOE is updated slightly to a range of 3.50 to 3.75 to reflect the volume metric 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 23rd, 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 under operated lease-owned and are planned drill schedule. At closing, and reflective of purchase price adjustments, we received approximately $215 million for Franco's investment in our investment minerals portfolio. Continental and Franco plan to invest an additional $375 million in minerals over the next three years, subject to achieving agreed upon development thresholds. Continental's portion of the investment is $75 million and 20% of the total investment over the next three years to earn 25% to 50% of the revenues based on achieving predetermined targets. We anticipate achieving the fully 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 exemplifies our mineral strategy. We plan to 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 stronger coast pricing, strong seasonal demand, and lower cushion 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 a 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.

Questions and Answers:

Operator

Thank you. Ladies and gentlemen, if you have a question at this time, please press the * then 1 key on your touchtone telephone. We ask that you please limit yourself to one question and follow-up question. You may then return to the queue. If your question has been answered or you wish to remove yourself from the queue, please press the # key. To prevent any background noise, we ask that you please place your line on mute once your question has been stated.

Our first question comes from Drew Venker with Morgan Stanley.

Drew Venker -- Morgan Stanley -- Analyst

Hi, everyone. 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 2019, whether that's a limitation on the upper end of growth, or first achieving your debt targets, and then maybe you'd look to return cash, is kind of how you're thinking about that?

John Hart -- Chief Financial Officer

Yeah, I think we're gonna 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. We see it in a fairly reasonable timeframe. You've heard us in previous quarters talk about -- and I would say the same today, but we've talked about dividends. That tells you that if we're talking about those things, we're honestly expecting to generate 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.

Drew Venker -- Morgan Stanley -- Analyst

Okay, thanks for that. 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?

Harold Hamm -- Chairman and Chief Executive Officer

Yeah. It all comes back to supply and demand in the world. And we still see demand strong. We've got 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 from the U.S., but if we go forward with Iranian sanctions, as I anticipate, take another 800,000 barrels off the market, long-term, things are gonna get tight. And so, we expect it to be pretty close going forward through the end of the year. So, oil processing is gonna be strong, and hopefully, we'll have a cold winter. Keep us there with natural gas.

Drew Venker -- Morgan Stanley -- Analyst

And Harold, as it relates to the hedging strategy, is that -- that means for the foreseeable future, no interest on hedges?

Harold Hamm -- Chairman and Chief Executive Officer

Yeah, I'm sorry, I didn't address that. We do anticipate -- we of course will hedge natural gas as we have the opportunity. We have a program ongoing with that. But with oil, right now, we're gonna remain unhedged.

John Hart -- Chief Financial Officer

Great. Thanks, Drew.

Drew Venker -- Morgan Stanley -- Analyst

Thanks, guys.

John Hart -- Chief Financial Officer

Thank you.

Operator

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

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Thanks. Good morning, everybody.

John Hart -- Chief Financial Officer

Morning.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

John, I wonder if I could take up on Harold's comment about offering a five-year look at some point. I just thought, at a high level, how should we think about how the company redeploys its -- was gonna be, it looks like, significant free cash? And I guess what I'm really thinking about here is, this is gonna 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 being redeployed to other areas outside of the current core areas such as the Permian. So, any help you can --

John Hart -- Chief Financial Officer

Sure.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

For example, 40% of the cash flow 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?

John Hart -- Chief Financial Officer

Sure. I'll and address your questions. There's a lot in there, so if I miss something, ping me back. Our five-year plan and even beyond that, we have a view toward 10 years, is based on existing inventory. There is 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 expiration stage, so it's not really in our five-year currently. As we go forward and as we get greater visibility on that, it's certainly something that 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 five 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 assets that we have now. We are going to be focused 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 gonna hit them fairly expediently. And then with that, we talked about dividends before, and 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 environments; 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.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Go on, Harold. Go on, Harold, sorry.

Harold Hamm -- Chairman and Chief Executive Officer

We'll probably all be looking at stock buyback, as cheap as it is today.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Yeah. Well, it kind of begs -- leads me to my second question, if I may, and this is really more -- Jack, you know what's coming here. But your stocks stand 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 the inventory depth 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, 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.

Jack Stark -- President

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 II, 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 lease hold position of 800,000 acres out here. And so, we're drilling in quite diverse areas and continuing to expand that. And our teams have type curves all across this field.

And we -- as time goes on, we're gonna 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, that 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, you should really get great comfort with that. And it is in -- and when we pull out -- when we talk about our five-year book on what we believe -- our five-year plan here, as we get around to the first year, we talked about that a bit, I think you'll get a comfort level on just how strong the Bakken is as a part of that growth.

Harold Hamm -- Chairman and Chief Executive Officer

Yeah, and don't forget the wells that's above that 1.2.

Jack Stark -- President

Oh yeah.

Harold Hamm -- Chairman and Chief Executive Officer

That blended average. So, it's a lot of wells after 2 million barrels EUR.

Jack Stark -- President

Yeah. We've got wells out there, as you know, with individual zones where you get in excess, too. Then you get some below, and that's the 1.2, is our average.

John Hart -- Chief Financial Officer

Doug, remember, we're one of the few companies that guides 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 2018, 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.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Yeah. I'll take that offline, John. But I appreciate the five-year guide, guys. 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 weeks. Thank you.

John Hart -- Chief Financial Officer

Thank you.

Operator

Thank you. Our next question comes from Arun Jayaram with JPMorgan.

Arun Jayaram -- JPMorgan -- Analyst

Yeah. Good afternoon. Just some thoughts, John, as you think about some of the near-term Bakken DPS, how do you think the DPS could play out over the next two to three quarters?

John Hart -- Chief Financial Officer

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 gonna let them speak up on some of that today. Thank you for the question.

Ramiro Rangel -- Senior Vice President, Marketing and Human Resources

This is Ramiro Rangel. During the third quarter, we had record DPS, and they were really attractive. What happened is, there were significant Pad II 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 gonna be -- capacity is gonna be built. So, longer-term, we feel that we're in pretty good shape.

Arun Jayaram -- JPMorgan -- Analyst

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

Ramiro Rangel -- Senior Vice President, Marketing and Human Resources

Sure. I think a lot of it is going to be tied to future capacity. And we feel that there's probably gonna be about 700,000 to a 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 really feel that that's gonna 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 a 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.

John Hart -- Chief Financial Officer

Arun, as a little bit of additional color, recall that in the South, in SCOOP and STACK, we're looking at a sub-$2.00 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. That guidance is $3.50 to $4.50 corporatewide for the full year. We did indicate we expected to probably see it in the upper half, so that's signaling some up in the fourth quarter. You could see a buck or two bucks, say 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.

Jack Stark -- President

And Arun, I'd just add in there too that about 50% of our bond value's up in the Bakken, our firm commitments there. And those firm commitments are -- I mean, I think we'll probably be on what, sub-$4.00 on all of those barrels. And so, that really helps offset any kind of, say, widening one might see in the differentials here in the fourth quarter.

Arun Jayaram -- JPMorgan -- Analyst

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.

Jack Stark -- President

Well, it's really where we're at right now, they're just very early in their flowbacks right now. And we've nine flowing back and another eight that 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 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 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 yearend, possibly having some sort of a webinar, perhaps, to discuss the results. We'll just see. But right now, 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.

Arun Jayaram -- JPMorgan -- Analyst

Fair enough. I look forward to that five-year guide. Thanks a lot, gentlemen.

Jack Stark -- President

Yeah. And I will tell, it's oil. Oil's coming back with no problem. And they're starting out nicely. Thank you.

Arun Jayaram -- JPMorgan -- Analyst

Great. Thank you.

Operator

Thank you. Our next question comes from Jeanine Way with Barclays.

Jeanine Way -- Barclays -- Analyst

Hi. Good morning, everyone.

John Hart -- Chief Financial Officer

Good morning.

Jeanine Way -- Barclays -- Analyst

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 have a total of 16 rigs in the SCOOP overall, and you're ramping to 18 by yearend. So, we're just wondering what the non-Project Springboard rigs are doing, and how does the oil capital efficiency of whatever those rigs are doing compare to the Bakken and the Springboard?

Pat Bent -- Senior Vice President, Drilling

You bet. This is Pat Bent, and that is correct with eight gain. The other rigs outside of those 14, we have one in merge, and then we'll deploy another three by yearend on Woodford oil. And so, we'll keep our oil focus high throughout the end of the year.

Jeanine Way -- Barclays -- Analyst

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 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 toward 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. Thank you.

John Hart -- Chief Financial Officer

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 to 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 that 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.

Jeanine Way -- Barclays -- Analyst

Okay, great. Thanks for taking my questions.

John Hart -- Chief Financial Officer

Thank you.

Operator

Thank you. Our next question comes from Derrick Whitfield with Stifel.

Derrick Whitfield -- Stifel -- Analyst

Good morning, all, and thanks for taking my question.

John Hart -- Chief Financial Officer

Morning, Derrick.

Derrick Whitfield -- Stifel -- Analyst

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?

Josh Baskett -- Vice President, Oil and Gas Marketing

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 rail cars for the new standards.

Derrick Whitfield -- Stifel -- Analyst

Great. And then maybe moving over to the STACK, when you think back to your Q4 2017 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 three units you guys just announced and the comments that you have on page 14, which indicate Simba's results will help you define a development model for the STACK condensate window.

Gary Gould -- Senior Vice President, Production and Resource Development

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 three of them just giving us really strong results for the six wells. I think it's important to note that whether we optimize with six wells or with eight wells, it's gonna 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 eight wells, and in others, it may be six wells. In other words, three to four 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 PB10 from eight wells -- from six wells this quarter as we had forecast for eight wells. So, very good results this quarter.

Jack Stark -- President

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

John Hart -- Chief Financial Officer

Thanks, Derrick.

Derrick Whitfield -- Stifel -- Analyst

Thanks, guys.

Operator

Thank you. Our next question comes from Bob Morris with Citi.

Bob Morris -- Citi -- Analyst

Thank you. Jack, nice results in the STACK oil window. On slide 13, just continuing with that, you show that for the six-flow units, the uptick to 100 million MBOE. But you're still using a total unit EOR of eight million barrels, which implies 13 33 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 PB10 now?

Gary Gould -- Senior Vice President, Production and Resource Development

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. And 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.

Bob Morris -- Citi -- Analyst

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

John Hart -- Chief Financial Officer

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 four to six wells per zone is what we anticipate, we'll typically put in each of these reservoirs. And we expect to have on average about two wells per zone. So, that can mean six to eight wells typically per unit. And with that, we think that gives us the optimum economics for unit development.

Bob Morris -- Citi -- Analyst

Sure. I guess I was just -- with the outperformance in the future, if you joined eight well units, is there an orange bar then to be put on top of the green bar in the future on what is the eight well count units?

Gary Gould -- Senior Vice President, Production and Resource Development

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

John Hart -- Chief Financial Officer

Yeah. If we duplicate these results with eight wells, we're definitely gonna see that eight bar -- that present value from the eight wells climb. No doubt.

Bob Morris -- Citi -- Analyst

Yeah. No, that's what I'm looking for. Great results. Thanks.

John Hart -- Chief Financial Officer

Thank you.

Operator

Thank you. Our next question comes from Brian Singer with Goldman Sachs.

Brian Singer -- Goldman Sachs -- Analyst

Thank you very much, and good morning.

John Hart -- Chief Financial Officer

Morning, Brian.

Brian Singer -- Goldman Sachs -- Analyst

Can you talk a bit more about how the positive results you're seeing in the Bakken impacts your willingness to allocate increased capital and activity on a relative basis? I.e., do you see yourself shifting a bit more on a percentage basis toward the Bakken going forward? And then as more of a follow-up to Doug's question earlier, if we look at slide eight, where the majority of the wells have been drilled, or that you're highlighting here 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?

John Hart -- Chief Financial Officer

So, on the first part, on 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, we do have some geographic opportunity, and we have geographic opportunity with 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.

Brian Singer -- Goldman Sachs -- Analyst

And the second part?

Jack Stark -- President

Yeah. And on the second part here, Brian, looking specifically at page nine, if you're looking at that --

Brian Singer -- Goldman Sachs -- Analyst

Oh, page eight. I'm sorry to interrupt. Page eight.

Jack Stark -- President

Page eight. I'm sorry.

Brian Singer -- Goldman Sachs -- Analyst

On page eight, you've got that 30 by 40-mile box, right, where the majority of the wells are. And I just wondered what the inventory is within the box relative to outside the box, and when there would be a disproportionate shift away from area?

Jack Stark -- President

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

Harold Hamm -- Chairman and Chief Executive Officer

You can see some of the wells that Jack's talking about as definitely out of that 30 to 40-mile box already.

Jack Stark -- President

Yeah. We've often talked about, you know, you see wells up there close to Divide County that are outperforming at the 1.2 MBOE equivalent mode. So, anyway, I think just again, this is an expanding play through technology.

Brian Singer -- Goldman Sachs -- Analyst

Great. And then you mentioned -- it might have been John -- mentioned in the comments that you had nine crews running in the third quarter, and that's going down to six in the fourth quarter. Can you talk about what is more of a normalized number, or as you think about -- probably as you think about 2019, or I guess to what degree moving from nine to six is a function of timing and capital allocation versus efficiency gains?

Gary Gould -- Senior Vice President, Production and Resource Development

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

Brian Singer -- Goldman Sachs -- Analyst

Great. Thank you.

Operator

Thank you. Our next question comes from Ryan Todd with Simmons Energy.

Ryan Todd -- Simmons Energy -- Analyst

Operator

Mr. Todd, your line is open.

Ryan Todd -- Simmons Energy -- Analyst

Sorry. I think I was on mute there. Can you hear me now?

John Hart -- Chief Financial Officer

Yes.

Ryan Todd -- Simmons Energy -- Analyst

Great. Thanks. Maybe if I could follow up with one on the Bakken. You're running eight rigs at present, which is a little ahead of our expectation at this point. Obviously, you have 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?

John Hart -- Chief Financial Officer

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

Harold Hamm -- Chairman and Chief Executive Officer

And rate counts for 2019.

Ryan Todd -- Simmons Energy -- Analyst

Sorry, is eight rigs a good assumption to think about for 2019 in the Bakken, or will we likely see that go higher?

John Hart -- Chief Financial Officer

Well, we really haven't come out with our plan for 2019, obviously. But we do anticipate some additional rigs being added in 2019. We've added these rigs -- like you said, we're ahead of schedule here. We expect it to be about at eight at yearend. We're already there. And that's just basically us getting prepared for continued growth into 2019. And so, you will see some additional rigs coming into the play in 2019. We'll get more details on that as we get out our 2019 plan.

Pat Bent -- Senior Vice President, Drilling

And this is Pat Bent again. And like we'd indicated, we'll exit 2018 with eight rigs in the Bakken. I just want to mention that our rig acquisition activity is very opportunistic going into 2019, and so, we don't need to pick up every rig we see come by. And so, we have the opportunity to be fairly selective in any incremental rig activity going into 2019.

Ryan Todd -- Simmons Energy -- Analyst

All right, thank you. And then maybe one follow-up on an earlier conversation on cash priorities in terms of use of cash. I appreciate some of the discussion about the dividend. What would you need to see -- I know you're considering a dividend. What would you need to see to kind of -- to make that happen? Is it a question of -- do you need to get the debt down to the $5 billion target first? 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 to kind of -- to kick that off?

Harold Hamm -- Chairman and Chief Executive Officer

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

Ryan Todd -- Simmons Energy -- Analyst

Okay, so it would -- I guess you'd need to hit the debt target first before you can --

Harold Hamm -- Chairman and Chief Executive Officer

That's correct.

Ryan Todd -- Simmons Energy -- Analyst

Is that fair? Yeah.

Harold Hamm -- Chairman and Chief Executive Officer

Yes, that's correct.

Ryan Todd -- Simmons Energy -- Analyst

Okay. Thanks. I'll leave it there. Thank you.

Harold Hamm -- Chairman and Chief Executive Officer

Thank you.

Operator

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

Brad Heffern -- RBC Capital Markets -- Analyst

Hey, everyone. 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 six to eight wells per section, or is there a different way we should be thinking about that?

Tony Barrett -- Vice President, Exploration

Hey, Brad, this is Tony Barrett. So, when you -- the inventory -- 65 units was pretty much split evenly beyond the oil and the condensate windows. Of course, we have a really large acreage position in the gas window, which is about double the units that 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 five to six to eight wells per section, incremental wells per section, as we step forward in fully developing the stack.

Brad Heffern -- RBC Capital Markets -- Analyst

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

John Hart -- Chief Financial Officer

Sure. Out of the Bakken, a lot of our NGLs are priced out of Conway. But in Oklahoma, the preponderance, 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 gonna be built of new frack; and 2019, about 300,000; and 2020, about another 500,000. So, you're seeing a lot of new capacity that's gonna be built in Mont Belvieu, which should really help the industry a lot.

Brad Heffern -- RBC Capital Markets -- Analyst

Okay. Then no concerns about any constraints on fractionation capacity before the comes online?

Jack Stark -- President

It's gonna 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 and being able to built the fractionation that's needed.

John Hart -- Chief Financial Officer

Okay, thanks, Brad.

Brad Heffern -- RBC Capital Markets -- Analyst

Okay. Thank you.

Operator

Thank you. Our next question comes from Subash Chandra with Guggenheim.

Subash Chandra -- Guggenheim -- Analyst

Yeah, hi. Just back to the Bakken oil question. I guess with the takeaway of 700 to a 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?

Josh Baskett -- Vice President, Oil and Gas Marketing

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 will show up. Again, we're under confidentiality, so we can't share too many details there, but we certainly believe that's the future for the Bakken barrel.

John Hart -- Chief Financial Officer

We're always working to go to advantaged markets and looking for the best price. So, you can rest assured that's the focus and intent of our activities.

Subash Chandra -- Guggenheim -- Analyst

Yeah, sure. I was just -- from an urgency perspective, 'cause it looks like, at least based on production, it's 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 in? Are they sort of year or two-year lags, or do you anticipate anything quicker than that?

John Hart -- Chief Financial Officer

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 slog toward the end of the year. So, again, it's coming fairly soon.

Subash Chandra -- Guggenheim -- Analyst

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 from maybe the fourth quarter, something like that. And that was given before any of these rows were drilled, falling back. Do you anticipate to fine-tune that, to reappraise that, or should we run with that for the time being?

John Hart -- Chief Financial Officer

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 what we expected, dedicate 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 problem sticking with that number.

Subash Chandra -- Guggenheim -- Analyst

Great. Thanks, all.

Operator

Thank you. Our next question comes from Neil Dingmann with SunTrust.

Neil Dingmann -- SunTrust -- Analyst

Good afternoon, guys. Thanks for all the details. Jack, maybe my question is for you and Gary. A couple of asked about the slide 13, but I always liked that slide of yours. Looking at sort of the optimal, the six to eight, are there variables, such as if you're able to pick up minerals under there, or if some well costs 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 down-spacing and all, especially if you're able to add minerals under there?

Gary Gould -- Senior Vice President, Production and Resource Development

Yeah, 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 $100,000.00 and, say, $500,000.00 per well that are really being driven by stage efficiencies as well as lower profit cost.

Neil Dingmann -- SunTrust -- Analyst

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

Jack Stark -- President

Neil, I was just gonna say that John had mentioned that we have about 12% of the minerals underneath Project Springboard. But if you look at specifically underneath our leasehold, it's knocking on the door of about 17%. And so, that really starts showing how the value of these minerals are really gonna hit the bottom line here. Because in those units, we end up with 100% net revenue.

Neil Dingmann -- SunTrust -- Analyst

Yeah, 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, being 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 30-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 kind of gave a supply/demand picture -- just again, being the service expert, I wonder what Harold thinks about the service costs sort of at this level.

Pat Bent -- Senior Vice President, Drilling

Yeah, 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 is where we're currently at and where we intend to stay through 2018 and into 2019.

Harold Hamm -- Chairman and Chief Executive Officer

Yeah. My perspective long-term on service costs are that what these companies really needed was utilization. And now we're seeing that across the industry. A lot of them are pretty much 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 the time. And so, instead of just forcing prices up continually, getting more efficient and with more utilization, we think it could stay in about the same plane that it's in today.

Neil Dingmann -- SunTrust -- Analyst

Thanks for that perspective, Harold. Appreciate it, guys.

Operator

Thank you. Our next question comes from Daniel Osley with Wells Fargo.

Nitin Kumar -- Wells Fargo -- Analyst

Hi. This is Nitin Kumar from Wells Fargo. Hey. Hi, guys. Just maybe one question. One of the comments you made is about $650 million of the capital this year was spent for 2019. Thinking average costs around $10 million or so per well, that suggests you would have a DUC inventory -- not even a 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 five-year plan?

John Hart -- Chief Financial Officer

Well, recalling that $650 million, it can be -- the wells it's 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 that to calculate. I don't have the projected DUC count at yearend 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 just asked about the third quarter. We spent a lot of capital on the third quarter completing wells. We're getting the production this quarter. We're spending some capital now, and we'll get another slug of production in 2019. So, that's just the normal cadence and pace.

Jack Stark -- President

And recall, everything that we do in the Bakken is on large pads. And in the South, it's more and more pads today than certainly, compared to two or three 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.

Gary Gould -- Senior Vice President, Production and Resource Development

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

Nitin Kumar -- Wells Fargo -- Analyst

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

Gary Gould -- Senior Vice President, Production and Resource Development

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 gonna be getting those wells on maybe a little earlier than the midpoint of this quarter.

Jack Stark -- President

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

Nitin Kumar -- Wells Fargo -- Analyst

Perfect. And if I could just sneak one in, you talked about increasing activity, maybe directionally, as you talk about fee cash flow and dividends, so what is the price that you are willing to consider for your budgeting exercise for 2019?

Jack Stark -- President

Like commodity price?

Nitin Kumar -- Wells Fargo -- Analyst

Yeah.

Jack Stark -- President

Well, I mean, commodities move. We generally are starting with kind of a $60.00, $65.00 price, but then we're running scenarios 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 that 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 $5.00 increment from there.

John Hart -- Chief Financial Officer

And we're gonna leave it there.

Operator

Thank you. Our next question comes from Matt Portillo with TPH.

Matt Portillo -- TPH -- Analyst

Good morning, guys.

John Hart -- Chief Financial Officer

Hey, Matt.

Jack Stark -- President

Good morning.

Matt Portillo -- TPH -- Analyst

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 phases differentials going forward. I was wondering if there's any color you might be able to provide on that 700,000 to a million barrels of takeaway, how much of that would potentially be brown field versus new green field projects, and if there's any high-level color you might be able to provide in terms of kind of the capacity adds that might be weighted toward 2019 versus 2020-plus?

Harold Hamm -- Chairman and Chief Executive Officer

Let me try. Well, first off, if you look at Dapple and the size of that line, you know that you get expansion capabilities there, that's gonna be almost 40% more capacity that's gonna come on with that eventually. That was from the initial projection to where that's gonna go. So, that's a good bit of capacity right there that they'll be adding. And the next is new construction. Obviously, as Jack pointed out, there's a lot more oil to come out of the Bakken. And so, these new pipeline projects are gonna pay off beautifully as time goes on. So, there's gonna be a lot of brown field/green field pipe to be added.

Jack Stark -- President

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

Matt Portillo -- TPH -- Analyst

Thank you very much. That was my only question.

Harold Hamm -- Chairman and Chief Executive Officer

Thank you.

Operator

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

Marshall Carver -- Heikkinen Energy Advisors -- Analyst

Yes, thank you. 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?

Jack Stark -- President

Hm. Give us a second. We haven't got the number here at hand. We're pulling that up. Why don't you go to your next question while we're looking for that, and then we'll come back to that.

Marshall Carver -- Heikkinen Energy Advisors -- Analyst

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

Jack Stark -- President

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

John Hart -- Chief Financial Officer

They're getting close on the number.

Marshall Carver -- Heikkinen Energy Advisors -- Analyst

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

Jack Stark -- President

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

Marshall Carver -- Heikkinen Energy Advisors -- Analyst

Okay, that's helpful. Thank you, that's all for me.

Jack Stark -- President

Thank you.

Operator

Well, 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.

Jack

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

Operator

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.

Duration: 76 minutes

Call participants:

Rory Sabino -- Vice President of Investor Relations

Harold Hamm -- Chairman and Chief Executive Officer

Jack Stark -- President

John Hart -- Chief Financial Officer

Ramiro Rangel -- Senior Vice President, Marketing and Human Resources

Pat Bent -- Senior Vice President, Drilling

Josh Baskett -- Vice President, Oil and Gas Marketing

Gary Gould -- Senior Vice President, Production and Resource Development

Tony Barrett -- Vice President, Exploration

Drew Venker -- Morgan Stanley -- Analyst

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Arun Jayaram -- JPMorgan -- Analyst

Jeanine Way -- Barclays -- Analyst

Derrick Whitfield -- Stifel -- Analyst

Bob Morris -- Citi -- Analyst

Brian Singer -- Goldman Sachs -- Analyst

Ryan Todd -- Simmons Energy -- Analyst

Brad Heffern -- RBC Capital Markets -- Analyst

Subash Chandra -- Guggenheim -- Analyst

Neil Dingmann -- SunTrust -- Analyst

Nitin Kumar -- Wells Fargo -- Analyst

Matt Portillo -- TPH -- Analyst

Marshall Carver -- Heikkinen Energy Advisors -- Analyst

More CLR analysis

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