Continental Resources, Inc.
Q1 2019 Earnings Call Transcript

Published: 1 May 2019

[Operator:]

Good day ladies and gentlemen and welcome to Q1, 2019 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. [Operator Instructions] As a reminder, today's conference may be recorded. I would now like to introduce your host for today's conference Mr. Rory Sabino, Vice President of Investor Relations. Mr. Sabino, you may now begin.

[Rory Sabino:]

Thank you, Sharee [ph]. Good morning and thank you for joining us. I would like to welcome you to today's earnings call. We will 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; Steve Owen, Senior Vice President, Land; Ramiro Rangel, Senior Vice President, Marketing; Tony Barrett, Vice President, Exploration; Josh Baskett, Vice President, Oil & 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 on 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 $60 per barrel WTI and $3 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. Prior to begin the prepared remarks from Harold, Jack and John, I would like to address an erroneous posting from a third-party web hosting service to our corporate websites this morning. As some of you may have seen prior to it being removed, our corporate third-party web hosting service inadvertently posted Campbell Soup Company's Analyst Day scheduled for June 13, 2019 our corporate website. This was a human error unrelated to Continental Resources resulting in the web hosting company placing events in the wrong corporate database after posting our slide deck this morning. This issue was addressed as soon as we were made aware of the third-party error. The correction has been. And if you look at the corporate events section of the Campbell Soup Company, you will see this event listed in their corporate events. I want to make it abundantly clear. There is absolutely no plan for Continental to host an Analyst Day or any other business update of any kind beyond or normally scheduled quarterly releases. With that, I will turn the call over to Mr. Hamm. Harold?

[Harold Hamm:]

Good morning everyone. Thanks for joining us on our call today. Over the past two decades, Continental has captured a very large portion of the best shale resources in the U.S. which has positioned the Company well for the future. We're benefiting from those first mover actions by developing these high-quality assets with low best-in-class operating cost. This has been our success formula, which is underscored once again by our team's strong executions in our first quarter results. We saw 2018 become the breakout year we envisioned and 2019 has proven to be equally fulfilling as our teams embrace the strategic shift to unit development within these larger project areas, all across our broad oil rich inventory. We have initiated the first year of our five year vision for sustainable, cash flow positive and oil-weighted growth to again almost double production. We also remain firmly focused on strong corporate returns. As you can see on Slide 6 of our investor deck, our corporate returns compete against all industries and nearly doubled the average of the E&P industries. During the first quarter of 2019, we applied our latest technological and cost-efficient completion optimization to legacy areas in three separate geologic domains of the Bakken with tremendous success. On Slide 8, you can see the details of these three strategic step-up tests that confirm uplift of well performance across North Dakota and Montana. These results confirm what we've been saying about the Bakken and it continues to get better as the nation's leading high quality oil play, and our Bakken production grew by more than 15,500 BOE per day for 8% growth quarter over quarter. In a closely watched SpringBoard area, the production is forging ahead of forecast with the first 28 days of April averaging approximately 14,000 barrels of oil per day. The exceptional execution in SpringBoard is another example of our team being industry leaders in a play we own and Jack will provide detailed on these significant events later on the call. Next, Continental teams delivered a low best-in-class LOE cost of $3.59 per BOE. Recall, we're a two stream reporting company and these low production costs are almost unheard of for a company our size and for oil-weighted production mix. In our Oklahoma region, our drilling and completion crews produced even faster cycle times by lowering drill days, intent upon reaching current technical limits in drilling, giving us the option of further reducing rig activity later on in the year. This is the definition of efficiency and excellence that our teams at Continental continue to achieve every day. Oil differentials have improved as planned for added pipeline, takeaway capacity materialized from the Bakken. Additionally, WTI has narrowed the spread between Brent pricing as more pipeline infrastructure is being ready to deliver domestic light sweet crude to the international market. Prior to concluding, I would like to highlight our teams' success in acquiring minerals, which is ahead of schedule underscoring our strong execution. Public equity markets continue to recognize the value creation of mineral strategies. We believe our approach is a unique vehicle for enhancing shareholder value and return, as we continue to capture minerals under existing drill schedule. We look forward to providing the market further updates on the long-term benefit of this relationship, which we believe may carry multibillion dollar potential for the Company. All of these achievements have been realized to allow to deliver the last part of our success formula and that is, net earnings of a 187 million for the quarter. In conclusion, if you turn to Slide 13, you will see that there is no other management team who align with shareholders. This is not only across the E&P universe, but also the broader market. The successful formula at Continental is simple, a powerful oil-weighted inventory coupled with industry leading cost, equal sustainable cash flow positive growth and returns that compete across the market. Now, I'll turn the call over to Jack Stark for further detail.

[Jack Stark:]

Thank you, Harold, and good morning everyone. I want to thank you for joining us on our call. Our Bakken assets delivered another outstanding quarter with production up an impressive 24% year-over-year. We completed another 55 wells uploaded an average initial rate of 2,300 BOE per day and 80% of the production was oil. As you know we have moved to multi-zone unit development in the Bakken, utilizing our optimized simulation technology. Since early 2017, a total of a 194 optimized development wells have been completed in 23 separate units and the results have been outstanding. In fact, the entire 194 development well program paid out in the first quarter of 2019. Wells in the top 10 performing units are projected to deliver an average rate of return of approximately 100%. The location of these units are shown on Slide 7 with the top 10 performing units highlighted in red. The key takeaways here are. One, outstanding results are being realized across a broad cross-section of our acreage. And two, multi-zone unit development of our Bakken assets is delivering results as advertised. Now, as Harold mentioned, the big news for the Bakken this quarter is the result from three strategically placed step out wells announced yesterday. These three wells prove our optimized completion technology continues to uplift well performance from the southern extent of our acreage in North Dakota all the way out into Montana. As expected, these three wells are outperforming nearby legacy wells by 82 on 110% during the first 60 days and preliminary estimates show these wells are delivering up to 100% rates of return. This is great news for our shareholders as we can confidently say that the value and the performance of our inventory of approximately 4000 Bakken wells continues to grow. We can also say that the core of the Bakken as many like to call it, just got bigger. The location of these three wells can be seen on Slide 8. In Montana, the Baird Federal flowed at an initial rate of 1,680 BOE per day and the 85% was oil. The Burian located in Southern Billings County, North Dakota, flowed at initial rate of 2400 BOE per day and 80% was oil. In East Central Williams County, North Dakota, the McClintock flowed at an initial rate of 2,440 BOE per day and 80% was oil. Now, let's move South in Oklahoma where we have more great results to share. As Harold mentioned, production growth in our SCOOP SpringBoard project is running significantly ahead of schedule. Production for the first 28 days of April has averaged approximately 14,000 net barrels of oil per day. Only 2,500 barrels shy of the 16,500 barrels of oil per day we had begun -- had been targeting by the third quarter. Our current projections show that SpringBoard oil production is likely to reach 18,000 barrels a day in the third quarter. This outperformance is directly tied to our cycle time improvements in higher lead time well performance. This quarter we announced our first Woodford completion since SpringBoard and results have been excellent. The six Woodford for completions highlighted on Slide 10 averaged 1,660 BOE per day per well and 75% of the production was oil. Early time, these unit wells are outperforming our legacy 1.5 million BOE per tight curve for the Woodford oil window. This reflects the performance uplift expected from today's largest simulations and validates the current plans to develop the Woodford with 5 to 6 wheels per unit. Our Springer development in SpringBoard is proceeding as scheduled. We have drilled 25 of the 31 Springer wells planned for Rose II and III and completion work is underway. We expect to have results from Rose II and III by our next earnings call, but I can say that early rates from a couple of wells have just started falling back look solid. Projects SpringBoard as a whole, we currently have 39 wells producing, 33 wells completing and 9 rigs drilling ahead. I want to point out that our recount SpringBoard is down by three rates from last quarter. Cycle time improvements, we have realized in the project or allowing us to achieve our objectives for the year with 25% fewer rigs. There's no better proof of the efficiency gains our teams have achieved in that. These three rigs have been reinforced to other SCOOP assets. In STACK, we brought on two outstanding fully developed units in the Meramec condensate and oil Windows. The 5-well Tolbert unit flowed at an impressive combined rate of 5,900 barrels of oil per day, and 77 million cubic feet of gas per day, or 3,740 BOE per day per well. This 2 mile unit included three wells in the upper Meramec and two wells in the lower Meramec. Like our previous Simba and Boden units, the Tolbert unit wells on average are outperforming our parent-type curve for the over-pressured condensate window of STACK. In the over-pressured oil window, we finished development of the three wells Lugene unit, which consisted of 3, 1-mile wells. The three wells flows at a combined initial rate of 4,620 barrels of oil per day, and 20 million cubic feet of gas per day, or 3090 BOE per day per well. The Lugene wells are strong producers, slightly outperforming our 2-mile unit type curve for the over-pressured window during our first 60 days. In addition to our unit development activity, we recently completed our first 3-mile Meramec lateral and STACK called the Blondie 1-6-7-18XHM. The well flowed at an initial rate of 2,460 barrels of oil day in 5.6 million cubic feet a gas day or 3,400 BOE per day. As we continue to deliver strong repeatable results in STACK, I think it's worth noting what is driving these results. Our successes have driven primarily by geology. As we've always said, our acreage is located in the over-pressured window STACK and underlying by some of the sickest and best quality Meramec reservoir in STACK. To illustrate, Slide 12 shows all Meramec wells completed from January 15, 2015 to-date that produced at an average initial 30-day rate of 1,500 BOE per day or more based on public records. Continental wells are highlighted in red on the slide. Two things are evident on this map. First is that the vast majority of the high performing wells are found in the over-pressured window. Second is the correlation between the superior performance and Continental's acreage position is evident. In addition to being in the right geologic zip code, proper well density is also critical to unit development and well performance and we established that quite a while ago. In addition to excellent well performance we're experiencing in both SCOOP and STACK, our operating efficiencies continue to reduce cycle times and cost. As I mentioned before, our cycle times in SpringBoard have come down dramatically with a Springer drilling cycle times down nearly 30% from row one. Total completed well cost for Springer, our SpringBoard, Springer and Woodford wells are down almost $500,000 per well from our original 2019 budgeted costs. In STACK, our drilling costs per lateral foot have come down almost 16% this year. These operating capital efficiencies are materially celebrating our pace of developments and reducing costs. This in turn provides added flexibility for the allocation of rigs, capital and production growth. John will get into this further, but I want to thank our teams for their hard work and ingenuity that keeps Continental the lowest cost producer among our oil weighted peers. With that, I'll turn it over to John.

[John Hart:]

Thank you, Jack. We're off to a great start in 2019 with first quarter results reflecting the strength of our team's execution. As we released last night, our earning solidly beat consensus, driven in part by strong oil focused production was significantly improved oil differentials. First quarter production came in at more than 332,000 BOE per day. Oil production for the quarter was approximately 194,000 barrels per day, up 4% over fourth quarter 2018. As we predicted last quarter, we have seen improvements to our corporate oil differential in the first quarter, coming in at a much improved $4.77 per barrel towards the lower end of our 2019 guns. Our current expectation is for production in oil differential rentals to remain strong into and throughout the second quarter. Our gas differentials came in at an average negative $0.60 for the first quarter, negatively impacted by January and February market conditions. We have subsequently seen significant improvement with March at a much improved negative $0.36. We currently expect full year of gas differentials to be within guidance. In addition to strong production and oil differentials, our cost structure continues to be amongst the very best of our industry, as represented on slides 4 and 5 in our investor deck. In the first quarter, we remained with him or better than all of our cost guidance measures, G&A and production expense both came in below our guidance range with an oil-weighted production expense of $3.59 per BOE and total G&A of $1.50 per BOE. Continental is consistently among the very best in margins generated by low cash cost and high return oil weighted assets. We are pleased with our performance against these guidance measures. As we proceed through the balance of the year, we will continue to assess our results and we will update guidance as appropriate. Obviously, we are performing exceptionally well versus guidance. Regarding CapEx, as Jack mentioned, we have seen rapid improvement in our cycle times in both drilling and completions during the first quarter and our teams are performing at a very efficient level. These efficiency gains result in lower well costs and improve rates of return while at the same time increasing the number of wells that we are able to drill and complete with a static rig and completion crew count. Therefore, our first quarter 2019 CapEx came in higher than originally budgeted as we were able to spud an incremental 6 net wells and had first production on an additional 8 net wells versus our original budget. Our current plan is unchanged targeting the 2.6 billion capital budget for the year. Our higher level of spend in the first quarter is a product of our success in mineral acquisitions and operational efficiencies as I just covered. We do recognize that oil prices are well above the $55 price at which we budgeted and provided guidance. At $55, we were projecting free cash flow of 500 to 600 million. Recall that every $5 change in WTI is about 325 million in free cash flow for the year. We are now through a quarter of the year and with the rise in oil prices, we are tracking toward 1 billion of free cash flow for 2019. We are strongly committed to meeting our corporate objectives and this incremental level of cash flow will enable us to accelerate our debt reduction timing, reducing net debt to 5 billion or below this year assuming current commodity prices. We can easily adjust to be within our 2.6 billion budget for 2019 while performing well on all of our other guidance. If these higher prices are sustained, we will make a determination of the proper use of additional cash flow later in the year. Any use of the incremental cash will be prioritized towards debt reduction and building free cash flow. As mentioned earlier, our pace of mineral acquisitions is going well in our new venture with Franco-Nevada. During the first quarter, we closed the mineral acquisitions of 51 million. Recall that Franco-Nevada covers 80% of the acquisition cost and we split revenues based on hitting performance targets. As we are acquiring in areas we expect to develop near term, we expect a 50-50 revenue split. The acceleration in SpringBoard production benefits our minimal portfolio, as we own approximately 19% of the mineral royalties underlying CLR's leasehold position in SpringBoard. In summary with strong corporate returns, low-cost operations and high-quality asset, we remain confident in our 2019 outlook to deliver 13% to 19% year-over-year oil production growth alongside exceptionally strong free cash flow favorably benefited by recent improvements in crude oil prices. With that, we're ready to begin the question-and-answer session of our call and we’ll turn it back to the operator to take questions. Thank you for your time this morning.

[Operator:]

Thank you. [Operator Instructions] Our first question comes from Doug Leggate with Bank of America.

[Doug Leggate:]

I think the first question John for you, if I may. The talking toward the goals of free cash, I've got on a multiple theses to this question I guess because your costs are clearly trending lower, although you haven't chosen to change that guidance yet. Your differentials are running better and obviously your pace of development through the course of the year looks like it's running ahead of schedule as well. So I just wanted to kind of pull a lot together and to stay, but your last comment was you’re going to remain committed to reducing debt and maximizing free cash flow. But should I interpret that then that you're not changing $2.6 billion capital budget irrespective of all the great things you’ve done so far this year? Because clearly, you've got the flexibility to if you chose that?

[John Hart:]

We’re comfortable where we’re at. We’re four months into the year. And as you referenced on guidance, we’re doing extremely well on a lot of that. We’ll continue to monitor that data and update as we go throughout the year. We don’t see any reason to adjust the CapEx budget today. We’re doing, like I said, doing exceptionally well and we’re going to deliver strong results with that.

[Doug Leggate:]

Sorry, John, to level with you on this point, but because you’re running ahead of schedule, obviously, you’re spending more early in the year. So, if you continue to develop -- would that mean, you would slow down to stay within capital? Or you see what I mean because as obviously you’re going to be upward pressured because of your efficiency gains not so much because you’re spending more. Did you slow things down just to stay within 2.6 or how should we think about that?

[John Hart:]

I think we can certainly moderate our level of activity throughout the year. We also have different working interest in projects. We don’t have a lot of term contracts. Of the term rig contracts, we’ve got 90% of them expire this year. Even where we're at today and just projecting up consistent throughout the rest of the year, we wouldn’t be over that much. So, it’s not a large stretch for us to adjust. And so, I think we’re very comfortable where we’re at today.

[Doug Leggate:]

My follow-up is for Jack, hopefully, just a quick one. Jack, I'm not sure I interpreted the comment on the drilling, the backlog, while the inventory in the Bakken correctly. Your step-out wells are clearly bringing none -- what you previously second-tier or non-core areas enters you could expanding the core? But what was included in the 4,000 locations? Was that already assuming that this acreage was perspective? Or I guess another way to ask you, is how heavily risk was your acreage before? And how risk do you see at, going forward now? I’ll leave it there. Thanks.

[Jack Stark:]

Good question, Doug, and our 4,000 locations that we've talked about still stands. It did include these areas. We already saw these are being part of our portfolio to ultimately develop, but what’s happened here as a result of our optimized completions, the value of that inventory has been uplifted and significantly. And so, it is just a very -- just a methodical continued process here that we’re going through to demonstrate that our optimized standard, our operating value all the way across the field. And if you look at the slide on Page 8 as well, you'll notice that there is just a constant growing pattern of wells that have exceeded matter -- exceeded a 100,000 barrel in the first 90 days. And so, this is a phenomenon that’s happened across the whole field. This just -- historically, the Bakken has been under stimulated. And now that we’re actually properly simulating the zone, we’re really starting to unleash the true potential of the play.

[Operator:]

Thank you. Our next question comes from Drew Venker with Morgan Stanley.

[Drew Venker:]

Good morning everyone. Really, really strong quarter in light of even some really harsh weather. Could you just talk about how you see the pace of volume sort of progressing as I guess SpringBoard ramps up and it seems like you had a lot more momentum in the Bakken than I would have anticipated?

[Harold Hamm:]

Drew, that's a good question. Our teams -- we've been working up very long time. All these guys working, yes, that's where they live, that's what the deal with. And so, we've handled the weather situation better than most companies, and due to that, so it's -- they get it done very well. We are seeing -- production increased as we go forward, coming out of that first quarter. So second half, we'll see additional production come on. And you've referenced SpringBoard and certainly that that's going to add a great deal to the second quarter production and particularly in second half here.

[Jack Stark:]

I mean, we've got a slide on -- Slide number 9 that gives you a bit of an update on SpringBoard also. We're showing instead of 1605 in the third quarter, this year, we're expecting to be 18,000 or so. So, we are uplifting that. You're seeing some improvement there and that's all indicated. We're showing sequential growth in production throughout the year. And again, as you know, it's very much focused on all. So, we feel very good about where we're at.

[Drew Venker:]

Understood. Thanks for the details. As a follow-up on the Bakken step-out program, can you talk about how many wells and what area you plan to be testing later this year?

[John Hart:]

Drew, we have done this. If you've noticed on our map on Page 8, we've -- basically, we drilled well a well as far as South as we could and as far West as we could. So, we feel pretty good that the areas in between are going to respond. And so and we are pushing it further to North and we'll continue to do that as well. But you know our attempt here was to demonstrate as quickly as possible that this technology that we're using is uplifting the performance all across the play. And I think you can't ask for any better evidence than what we've shown here right now with these extreme West and South and basically a northerly step-outs that are delivering just pretty much as expected, outperforming legacy wells and the really just performing as we seen all these optimized teams performed across the play.

[Harold Hamm:]

And, Drew, this evolution we've watched has really occurred over the past three years as we look forward to work with this technology improvement and compensation. So going back to end of it some of these legacy areas certainly is fun to apply the latest and see how this turns those areas on. So, it's really very exciting.

[Drew Venker:]

And is the authorized completion approach for the step-out areas similar in your process as to you the rest of the plan?

[Harold Hamm:]

Yes, Drew, they are -- I mean, we’re -- they vary in design, obviously, but for the area -- but what we're talking about is basically closer per cluster spacing and basically more stages and profit than we've historically used out in these areas. So, it's really the same model, applying it very effectively in each of these areas. And it couldn't be more pleased with the outcome we have had got.

[Operator:]

Thank you. Our next question comes from Arun Jayaram with JP Morgan.

[Arun Jayaram:]

John, I wanted to talk to you a bit about your full year oil guide. This quarter, you hit just below the midpoint of that 190 to 200 range and we think about the April production that you've highlighted in project SpringBoard. Can you give us a feel or maybe arrange for 2Q oil volumes at corporate wide?

[John Hart:]

No, I don't have the exact numbers in front of me, but we are continuing to show growth and maybe a little flatter here in the mid part of the year than as we get out into the latter summer, early fall, it starts to turn back up again. And that's just project timing. I think we talked about a little bit about that back in the February call. We're on these large pads with these large number units coming on, so probably a little flatter here, but then turning up nicely.

[Arun Jayaram:]

And similar question on CapEx. I think last quarter you've highlighted how CapEx would trend down I believe in 2Q, move up a little bit on project time in Q3, and kind of move down into Q4. Can you give us a little bit more color on your thoughts and perhaps to 2Q CapEx without mineral spend?

[John Hart:]

I think you did pretty nice job there. That is what we see second and third quarter coming down relative to the first quarter, fourth quarter down from both of those second, third, probably relatively consistent with each other. Obviously without minerals spend, you're nicely below $700 million. So, I think we've built a very good and yet I think you know this, but the key on the mineral spend is that 80% of that's a pass-through because of our carry relationship.

[Arun Jayaram:]

And just my final question is, where are we in the steps to kind of, to extract value from for minerals? Are you still comfortable with the $125 million of spending it without the reimbursement this year?

[John Hart:]

On the $125 million, we're doing very well on that. I think you're asking if we go -- if we use all of that what we do. Is that what you're asking me?

[Arun Jayaram:]

Exactly, exactly.

[John Hart:]

If you look to last year, we went in and adjusted the, the 125 is a per year type targets, but we have the ability with our partner if we both choose to move about some round within that program. So for instance, in the fourth quarter last year, we carried some from some of the amounts in the last year, we backed out of that net it back in there and we could literally do that. And in '19, it's all opportunity driven. And, you know, it's an economic opportunity as well as theology in our development plans. So, if need to be, we can make adjustments in conjunction with our partner we chose to. Right now, we're good where we're at.

[Harold Hamm:]

I might add, we're very pleased with where we're at right now, too.

[John Hart:]

Yes. Yes.

[Jack Stark:]

Thanks. Nice job here.

[Harold Hamm:]

We keep going as well as it is. That's great for both parties.

[Operator:]

Thank you. Our next question comes from John Aschenbeck with Seaport Global.

[John Aschenbeck:]

So for my first one, I just kind of had a follow-up to a question from earlier in the call. I was wondering how we should think about just the general progression on capital spending throughout the remainder of the year?

[Harold Hamm:]

Yes, I think the last question was Adam. Second, third quarter down from the first quarter and the fourth quarter down from there, it's right now is the lowest of the year. And with excluding minerals, they're both below 700 million and even with minerals we should be below that. So, we're in good shape.

[John Aschenbeck:]

Okay, got it, got it.

[Harold Hamm:]

I think the key is, the 2.6 billion for the year retaining as our budget plan for the year.

[John Aschenbeck:]

Okay, great appreciated the clarification there. And so for my follow-up just industry consolidation has obviously been the dominant topic in the industry as of late and with that I'd just love to get your general thoughts on how you view the current M&A environment and your thoughts on what Continental's role if any is likely to be as industry consolidator, especially if I just think of Continental historically you know has been a company that's grown considerably through exploration as opposed to M&A?

[Harold Hamm:]

Well, it has and we certainly have grown this company through exploration that strategic bolt-ons have always been of interest to us and just this last quarter, we've done several of those and we consistently do that within all areas of where we operate. I might say that there is an unusual amount of interest with acquisitions. I think across the sector, the E&P sector, I'm talking about there's realization that companies are undervalued. And certainly, we've seen a correction with some of that just recently. So anyway, we continue looking at strategic opportunities that come around and we've seen few of those recently.

[Operator:]

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

[Jeanine Wai:]

So I just wanted to follow up on Doug's earlier question on the CapEx budget and use of the free cash flow, assuming that oil prices stay constructive. In the past, you've talked about perhaps getting an early on activity in the following year. And so just wondering, are you thinking about that differently this year kind of given the narrative shift in E&P are no longer prioritizing or awaiting growth? So for example, I know there's a dividend conversation going on once you get closer to your net debt target. But with any additional free cash flow, are you any more likely now to go kind of below that 5 billion target within the extra free cash flow versus adding activity because I think you can reduce debt down to 4.2 billion based on what's callable and I know there's a delicate debt balance kind of between getting on return of capital versus progressing to a low debt model where you can defend a dividend at any oil price? So just kind of wanted to check in on this?

[Harold Hamm:]

Sure, we appreciate that Jeanine. Obviously there is an opportunity out there, if we choose to go with dividends certainly would open the door to a narrative that the Company hadn't participated in with investors. So, that is out there and we will be looking at that very closely, but we do want to you know get down to the point that we talked about with debt. And so, we could accelerate that you know to 2020.

[John Hart:]

Yes, you may have noticed in my script I said 5 billion or lower, the over lower was added this time. Yes, we expect it. Our target as we go forward, and I'm not saying it’s necessarily all this year, but that $4.2 billion we would eventually like to get down to that. We’re not putting up that level of cash flow for the not unless remaining this year to get all the way down there, but eventually we will get down to lot much lower than the $5 billion of target. And we’ve got a lot of options with the great asset base we’ve got, with debt reductions, with dividends, I think you laid a number of those out very well, setting up, outlying years anything, we’re chasing value, we’re not chasing just growth for growth through those things. So all of those options are things that can add to value.

[Jeanine Wai:]

And then my follow up question, it's more of a housekeeping question. I believe last year’s budget had about $600 million of CapEx that was allocated for as well that we didn’t produce until this year. And I was just wondering if you can remind us how much of this year’s CapEx budget is allocated for its production next year?

[John Hart:]

So the total budget for this year is about $2.6 billion, it’s not bad as it is. The D&C component of that is about 2.1-something. Of that, a little bit over $500 million doesn’t have first production until 2020. So the level of capital that we’re spending in this year’s budget on D&C with current year production it's about $1.6 billion. So I think you may be working towards maintenance capital numbers they're pretty low. So we’re in a very good shape to deliver on our plans.

[Operator:]

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

[Derrick Whitfield:]

Shifting over to the stack. What was the genesis behind the three mile Meramec lateral and are you planning more in 2019?

[Harold Hamm:]

The genesis was that our operating teams thought we could it and do it very efficiently, and it turned out we could. And we had a stranded quarter -- a stranded section that we decided we'll just go and develop from the same payout and so was able to do that. And we felt like because of the very, very preliminary we produced throughout the entire lateral. And this is the great well right there, we're beyond reporting single well they've been for long times. But this was certainly exceptional well that we thought everybody ought to know about it. It's in a very good place and the team did a wonderful job.

[Derrick Whitfield:]

And perhaps just my follow up regarding the Woodford update at project SpringBoard, the update looks little positive relative to you legacy 1.5 million bell type curve. Could you remind us of the spacing for the Woodford in this room and if the productivity of the well has exceeded your pre-drill expectations?

[Harold Hamm:]

We are looking at five to six wells per unit in here typically. And as you said the performance of these wells come on early time, come on very strong. And what we’ve done in here is used our latest stimulation technology as compared to our legacy in there. So we’re assuming what we would anticipate to get some uplift as a result of that. And also it’s based on these results early time it surely is supporting that five new wells, five to six wells density.

[Operator:]

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

[Neal Dingmann:]

Jack, maybe just adding on to Derrick's question there, sticking with the Woodford development. Could you talk about just continued expectations? And one on the variability, I'm looking at prior slides where you looking what you had like specifically with the pile well 24 hours. It's just a little bit higher, I think around 1,800 or so and a little bit oily. So I'm just wondering overall versus the last you had here, looks like not too far off but about the same 1,660 was about 75. So really my question is the expectations for that going forward as far as from a oil percentage and from an IP percent?

[John Hart:]

As you know, we've said the average for the Woodford, we're anticipating out here is about 70% of the oil, and that's because you get from an oilier side on the side. And as you move to the west of the unit project SpringBoard, you get a bit more gas here and get into that condensate window. So you're going to see a great regional change but the average we're talking about here is it's going to in that 70% range.

[Neal Dingmann:]

And then size wise, you're still anywhere so that the pile is a little bit more, I think closer to little over '18 versus closer to '16 expectation. Will that too, Jack, shift as you go east to west?

[Harold Hamm:]

I think that this is a very good outcome in here. These are unit wells that are coming in after a pair well in here and you'd expect to see a bit of degradation. Plus also remember what we've seen in here when we come in and do the density development, there is just -- with these walls that come on a little bit strong with the well, because of the amount of -- basically the stimulation has been pumped as we're stimulating these wells, it takes just a little while to get that water back out. But when they come back on, they come on strong, so anyway. So I think this is a fair expectation, going forward.

[Neal Dingmann:]

And then just lastly, Cognizant, not having the 2020 out there, obviously not even yet, just thoughts when you look forward towards the end of the year, next year on reallocation between the Bakken and let's just use the whole entire MidCon, because again you are getting such fantastic results obviously in both of these broader plays. So I'm just wondering as you all are stepping back, Jack, you here on the team are looking at it on a longer-term. Does it come down to just simply economics? Does it come down to the amount of inventory? I'm just wondering now when you are on a go forward, how you think about reallocation or if there will be any between the broader plays going forward?

[Jack Stark:]

I don't see a lot of difference of reallocation. We try to get by one year before we project what CapEx going to be next year. But we might see the expansion of CapEx the following year, but lot of things coming into it. And we mentioned earlier that we keep an eye on supply and try not to overflow the market as well. So that's several things as you mentioned and add that perspective that comes into it.

[Harold Hamm:]

The beauty of this, Neal, is that we do have that optionality as we move capital around if need to need be for whatever reason. But I'd refer you to our five year projection to look at capital allocation and there you can see in general we expect to see about 60% to 65% of our growth over that five-year period coming from Bakken. And I think that pretty well correlated with and that capital range is probably could be in that, maybe 60%, 50% to 60%, probably Bakken, 60%.

[Operator:]

Thank you. Our next question comes from John Freeman with Raymond James.

[John Freeman:]

On Slide 10, you all show the big cost reductions that you've had and the efficiency gains as you all switch the well bore design. And last quarter, you all mentioned that you all are close to begin testing of a new well bore design and the stack. And just curious if that started when we may get results or more details on that.

[Pat Bent:]

Yes, we have that stack, don't have that PD'd yet nor completed. And so that should be Q2 and we'll put some results then.

[John Freeman:]

And then just a follow up questions, it's a little bit of a follow up on what Neil was discussing. If I looked at just -- thinking about just Bakken relative to the five year plan. The step out wells, especially the ones in the West in Montana and then the one that was the extreme southern step up in the Bakken. Do those results -- do you feel those are significant enough to potentially change the allocation of activity within the Bakken relative to the five year plan?

[Harold Hamm:]

Sure, it can influence the allocation here as we try to maximize the value of any of these units with the infrastructure that's in place, all those types of things. And so again, what this does is just it proves that uplift the performance expands across our acreage and it gives us just more optionality for development.

[Jack Stark:]

One thing john that I'd throw in there is that we've got one other area here in Southern Oklahoma that’s also is begging for CapEx, its Woodford and after that and here in the south. I mean, obviously, the results that we've had in the stack that -- we've got Berry here that is also begging for additional CapEx that’s competing with that.

[Operator:]

Thank you. Our next question comes from Nitin Kumar with Wells Fargo.

[Nitin Kumar:]

I just wanted to touch base, John, you mentioned the Bakken differentials being stronger. They've widened out a little bit here early in April. Just your thoughts on what are the dynamics there and how should we think about going forward for here?

[John Hart:]

I think the Bakken differential obviously improved dramatically. You had a little bit of a blowout in December but we've seen sequential improvement through the first quarter April is looking as strong as well. We did guide a little bit wider this year relative to last year just taking some of that into account. We're at the low end of that guidance. I think what we're seeing going forward right now continues to be strong and improving differential. We just think over the next 12 months, the amount of takeaway capacity that you've got coming into the basin that will continue to benefit it and as well and that spread throughout the next few months, the next 12 months. So I think we feel very strong and we'll continue to monitor that and our associated guidance as we get throughout the year, but so far very good.

[Nitin Kumar:]

And just sticking with the Bakken here, I couldn’t help but notice that a step out well in the Montana, strong results obviously, but maybe about two-thirds of your IPs in the core of the basin in the North Dakota side. What are your well costs out there? That's question one. And then two, any type of plans with tested outcome?

[Harold Hamm:]

Well, let's just take on Montana first. I mean, the beauty of that area is that also you're only looking at that two-thirds of cost. It's got all the infrastructure in over there. We've got 50,000 better acreage -- acres there, we don’t to farm in. It's just the area that's got to rock we just need to go develop it. So it's a very good area. You're talking about Divide County, sure, you saw recently that there's a leap toward that area and we've seen some good results out there as well.

[Operator:]

Thank you. Our next question comes from Paul Grigel with Macquarie.

[Paul Grigel:]

Just following up on the Bakken there as you do step-outs. Is there a material difference in well costs as you look at Montana or Southern Billings County given they're a little bit shallower than the core?

[Harold Hamm:]

Yes, I just talked about that on the last question there, but you must been on the phone there, but the beauty…

[Paul Grigel:]

Well, I guess just actual drilling, Harold. I understand and appreciate the infrastructure and the land cost, but the actual drilling the D&C cost. Is that actually cheaper?

[Harold Hamm:]

Yes, it's shallower and both those areas that we just talked about. And so it's -- the drilling cost is cheaper and certainly I've mentioned the infrastructure. Jack, you might want to add.

[Jack Stark:]

When you look out of Montana, our costs out there were in that $6.5 million to maybe $7 million range. And so when you get down south there in Billings County, we're dealing more in about maybe 7.5 range there. And so as Harold said, the costs are down substantially there and the performance that we're seeing there is just growing. I mean, in Billings County, the way that Billings is performing here, we're looking at rates of return 100% or higher on our well there. And out there in Baird Federal, I mean we're looking at not going to do our 50% rates of return out there. So I mean that's really just excellent outcomes in each of these areas and we just have a lot of running.

[Paul Grigel:]

Thanks. And thanks for bearing with me on the southeast trying to get down to the infrastructure part there. I guess turning further south to MidCon. Jack, as you mentioned the three rigs were moved into different parts of the SCOOP. Could you talk with those drilling efficiencies, why they're moved there versus maybe other areas, either within the MidCon or Bakken especially reallocated them around?

[Jack Stark:]

They moved to other great areas down there in SCOOP and we're drilling, so you get to see some results with some of that activity here down the road. So anyways, they're all being put to good use.

[Operator:]

Thank you. Our next question comes from Leo Mariani with KeyBanc.

[Leo Mariani:]

You certainly did a good job highlighting some of the cost reductions that you've had on the SCOOP wells. I know you're expecting further 7% reduction. I think in your prepared comments, you talk about some efficiency gains in STACK as well. Could you maybe talk a little bit more about the well cost progression there in terms of where the costs may have been, say a few quarters ago where they are today and where you're expecting those STACK well costs to go later this year?

[Harold Hamm:]

Sure. I think we mentioned it last quarter that as we explore the wellbore design and stack, we would anticipate an additional 600,000 in savings to do those that. So that again is looking forward. Currently, when you look at down to liability and just lateral total refinement our costs drooped just through efficiency gains as a percent of it.

[Leo Mariani:]

And I guess just over to the Bakken side. Certainly, you've had some very nice step outs here. Wanted to get a chance of whether or not your geologic and economic models are projecting that you guys would continue to see wells that are as strong as you move up north into Divide County? Or do you think maybe those wells to be closer to some of the rates that you see in Montana versus a few of the more core counties in the Bakken?

[Harold Hamm:]

I think if you go to page eight, I think it’s just always interesting that there is a green dot out there in northeast part of Williams County almost in Divide that that’s a well that’s just over 100,000 barrels in the first 90 days. And so as we move up in that direction, I do think that we will see average EURs go down. But I’d also think as we talked previously well costs go down and returns are the key here and the value creation we’re going to be able to get. So I really think that we’re going to find the economics of what we see as we move further north, we’ll continue to compete with what we’re seeing down south, probably going to be a bit less little bit higher water cut. But bottom line is that we still think we’re going to have very economic performance out there.

[Operator:]

Thank you. Our next question comes from Subhash Chandra with Guggenheim Partners.

[Subhash Chandra:]

So Harold, since you brought up M&A and some of the things you might have looked at recently. I'm just curious that would they fall more in the tuck-in category? Or have you been rethinking your approach to corporate large scale M&A?

[Harold Hamm:]

No, I think these are mostly the tuck-in category bolt-on as we call them, strategic step within our operating areas, particularly and maybe or so than Bakken.

[Subhash Chandra:]

And my follow up is looking a little further down the path here. You’ll be done with the Springer wells at SpringBoard by 2020, and so some questions have revolved around. You'd have peak production at that point from SpringBoard and then what happens in 2021. So I'm curious if the Sycamore-Woodford program takes us forward from there for further growth, or is that when other SpringBoard's come into play?

[Harold Hamm:]

We had those SpringBoard, we just hadn't been pulling that after. We’ve talked about it that just hadn’t been pinpointed. And most of this is HBP stuff, so that’s a good part.

[Jack Stark:]

My response to it, Subhash, is it’s both. It is Woodford and the Springer -- other SpringBoard projects, because you’re going to find that there definitely is a potential to expand and obviously we have other sites on additional SpringBoard activity.

[Harold Hamm:]

But when you look into five year plan, you say that there's not a lapse in production out there.

[Operator:]

Thank you. Our next question comes from Biju Perincheril with Susquehanna.

[Biju Perincheril:]

A question about the first quarter oil volumes. Just wondering if there are any special one-time adjustments as stronger as it was given the uptick in Bakken and the SpringBoard volumes. I would have thought the company-wide oil number would’ve been higher. So can you talk about what could be the offsets to those two areas and how you see the oil mix progressing through the rest of the year for the year?

[John Hart:]

We have got it on the oil growth for the year 13% and 19%. And I think with that, you get to 60%, maybe even above 60% oil ratio on a two-stream basis. We feel exceptionally well about that. When you're looking at a quarter, you've got to realize that wells come on at various times throughout the quarter. And so what you're looking at SpringBoard as it's come on where we're at now and the stuff, it wasn't all on at the beginning of the quarter. So our oil volumes are doing great. You always have -- you asked about adjustments, you always have adjustments like that. We've also got new areas where production was offline or things, it all balances out. I think it is a very normalized number that we reported for the first quarter and it's a good benchmark that carries you forward. So we're in great shape.

[Biju Perincheril:]

And then my follow up, thinking about areas that can step out in existing areas. In the SCOOP, just on the southern portions of the SCOOP and Love County, there has been some pretty good Woodford walls. I think you've had some acreage there. Do you still have acreage and any close to touch that area?

[Harold Hamm:]

I was going to say that, we have got -- I mean, we have couple of those a few extra rigs out of SpringBoard and these are some of the work that we've been doing down there. I want to tell you that at this moment that we are actually in Wealth Country but what I'm saying is we have building, the option to go ahead and take care of that type of activity. As you see, there continue to be I guess I'd just say some interesting activity.

[Operator:]

Thank you. And our final question comes from David Meats with Morningstar.

[David Meats:]

I'm interest in those three non-core Bakken walls, which are very impressive. You guys already talked about that this is well cost over there. But I was wondering particularly in that Montana area. If there is any difference in typical gathering costs or it's the average working interest is different out there?

[John Hart:]

Well, working interests are very high. And we're 100% in the Baird Federal. So averages are going to be 80%, 90%.

[Harold Hamm:]

In our position out there, which is a sizeable position is we're in 80%, 90% working there.

[David Meats:]

So that's the working interest. And what about the gathering and transport costs. Is there any material difference between those costs out at Montana area or in the north?

[John Hart:]

No, we're really not seeing anything anomalous out there on that. I will tell you that the production out there in Montana though does have a tax benefit. For the first 18 months, it is that you end up getting your tax reduced down to just 0.5% for the first 18 months. So it's very nice bonus that you get for the production that you have on Montana.

[Harold Hamm:]

Its production even that's what developed area to begin with and certainly that's why we keep looking at.

[David Meats:]

And just my quick follow up here that on the motivation for drilling as well. But sounds like from your answers to other questions that you're just really testing the back end of the drilling here. And just wanted to make sure there's no plans based on these strong results to incorporate these areas more in your near term development plans?

[John Hart:]

Well, based on the results, we've got the opportunity to incorporate this and when they compete head-to-head with some of the -- with the inventory that was drilling. So what it does is it just essentially gives us a larger playing field here to develop.

[Operator:]

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

[Rory Sabino:]

Thank you very much for your time today. Please follow up if you have any further questions. Thank you.

[Operator:]

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