Continental Resources, Inc.
Q1 2018 Earnings Call Transcript

Published: 3 May 2018

[Operator:]

Good day, ladies and gentlemen, and welcome to the First Quarter 2018 Continental Resources, Inc. 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. As a reminder, this conference is being recorded. I would now like to introduce Vice President of Investor Relations, Mr. Rory Sabino. Please go ahead, sir.

[Rory R. Sabino:]

Thank you, and good morning, everyone, and thank you for joining us on today's call. I would like to welcome you. And before we begin, I would like to introduce myself and say I'm very proud to have joined the Continental team as Vice President of Investor Relations, following 20 years in the financial services industry at various investment banks. I have spoken and met with many of you and look forward to working with you in the future. 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; Tony Barrett, Vice President Exploration; Gary Gould, Senior Vice President, Production and Resource Development; Steve Owen, Senior Vice President, Land; Ramiro Rangel, Senior Vice President, 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 $65 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. With that, I will now turn the call over to Mr. Hamm. Hamm?

[Harold G. Hamm:]

Thank you, Rory. Our first detail is to welcome Rory to his very first Continental Resources call. And his background has worked very well preparing for the position that he now holds. He became an immediate contributor to our team here at Continental. So thank you, Rory. Hey. Good morning, everyone. Welcome to our first quarter 2018 earnings call. As we began the year that we have entitled our breakout year at Continental, we find our claim as being America's oil champion synonymous with the first quarter's operational results. Delivering on our guidance of cash flow positive growth, we have $207 million in free cash flow this quarter, primarily driven by better crude oil prices, which have been used to pay off our revolver and lower our debt even further. Our financials demonstrate we're returns-driven and our oil-rich inventory continues to drive our high margins and industry leading performance. Recognized in the industry as a leading independent oil company, our financial strength and operational efficiency and performance are underpinned by our oil-rich assets and I'll proudly highlight some of those today. As a result, our oil production growth year-over-year has grown 37%. 90% of our drilling activity through year-end is focused on core our top oil and liquids-rich plays generate right here at Continental. Of course, the world-renowned Bakken continues to exceed expectations quarter-over-quarter and this quarter is no exception, and Jack Stark will provide more detail operational on the Bakken. Perhaps just as important, he will provide color on a very strategic move to focus our activity on oil and our Oklahoma assets as we are nearing the end of our need to drill to HBP acreage in our JDA STACK and SCOOP and we will now enjoy 100% optionality for highest grade return wells and/or projects. For example, in our large oily Woodford SCOOP, we reported last quarter a Pyle well, which tested at 1,812 Boe per day and 81% oil. We also completed the Lillian well nearby this quarter at the certainly impressive rate of 1,593 Boepd and 74% oil. Jack will also give details on another oil shift to drilling resources in the STACK play which is equally as compelling and financially rewarding. I am particularly proud to personally announce that we have kicked off our SCOOP Springer row development and our Project SpringBoard, Continental owns approximately 75% of this project and 85% of the Springer production will be 46 gravity sweet crude oil. SpringBoard will have a major impact allowing Continental to achieve a higher level of crude oil production, operational efficiency and profitability for the next five years or more. Project SpringBoard is a multilayered portion of the SCOOP in the South Central Oklahoma oil play, which was named by Continental for its rich legacy of oil production. It was sourced and produced from the Woodford shale which are numerous rock layer including the prolific Springer Mississippi, and Sycamore and others. Combined with the STACK, these plays lifted Continental's daily production rate to become Oklahoma's number one producer in Boe in 2017 and will only get better. Continental was a grassroots first mover in this play. Our teams defined, delineated, drilled, cored and tested vertically before drilling horizontally. If you'll notice, few others are talking about this exciting play because we own it. As patient first movers, we were able to evaluate it with deeper Woodford wells, acquire it, and now own a vast majority of the project. We like it so much in fact we acquired 2,400 acres of minerals in the play. With the current crude oil pricing environment and excess inventory abatement, we believe finally it is indeed timely to bring on this development for the benefit of our shareholders and have committed five rigs to this very exciting high rate of return project. The best news with play you own and control this close to market is there are no drilling or production bottlenecks unless you create them yourself. There is an art to exploration and it's about as good as it gets. These are all great examples of frontline team efforts that continuously go on here at Continental and a few other reasons why Continental leads the industry as one of the lowest cost producers. On the past two quarters' calls, we have discussed our marketing team. We have announced Project Wildcat, another example of excellent teamwork. Wildcat provides additional takeaway capacity we need for projected growth from SCOOP and STACK. The team has also hedged the majority of our natural gas production at an average price of $2.88 for 2018. We have not hedged our oil production and are fully participating in the improved-oil prices as the supply-demand rebalancing continues to occur. We will continue to monitor this situation, but we are encouraged as the global economies acceleration has driven us new oil demand to 1.7 million barrels per day or more. We are also on the cusp of the upcoming driving season. It has taken since November 2016 when OPEC introduced their production cuts along with Russian to reduce the crude-oil overhang in the world to the current level. Petroleum inventories are slowly being systematically drawn down, which should bode well for stabilized oil prices for some time into the future. With all that being said and excited as we are being all too familiar with the lessons of the past five years at Continental, we will remain a low-cost producer, disciplined and vigilant, keeping our eyes on the market fundamentals and focused on maximizing returns to the shareholder. On the financial side of the business, we're proud to announce that on April 30, we received a public investment grade rating from Fitch. This is in addition to recent upgrades by both S&P and Moody's. John Hart will provide more details on this but we're excited about these ratings. We will grade ourselves on shareholder returns before bonus considerations are made and Continental has established industry leading metrics in this category. At Continental, we continue to embrace the founder's mentality and celebrate our strong alignment with our shareholders. Briefly, I want to highlight some of our team's outstanding performance this quarter. In North Dakota's Bakken, as ECO-Pad development progresses, we are now measuring drill wells in tens of days. (10

[Jack H. Stark:]

Thanks, Harold, and good morning, everyone. Appreciate you being on the call with us today. As Harold highlighted, the first quarter was all about execution and delivering on our guidance of cash flow positive growth. 2018 is off to a great start, with our operations, capital spend, production and cash flow essentially on track with guidance. Now I suspect many of you have seen recent articles that say that the Bakken is back or the Bakken is booming again. Well, I couldn't agree more. Bakken wells across the field are producing at unprecedented levels, uplifting the economics of the entire field. To illustrate, take a look at slide 13 in our slide deck. The distribution of all Bakken wells that have produced more than 100,000 Boe during their first 90 days, over two separate time frames, the last three years and the prior 15 years. As you can see, there has been a drastic increase in both the number and distribution of wells that meet this criteria over the last three years and the footprint is expanding rapidly. This is truly a step change in performance for the Bakken made possible thanks to the breakthroughs in completion technologies. Today, Continental stands as the number one producer in the North Dakota, Bakken, representing approximately 15% of the total production from the field on a gross basis. Our Bakken production in the first quarter was up 48% from the first quarter of 2017 as we continue to bring on record-producing wells. Three of the 31 Bakken wells we completed in the first quarter produced at record 30-day rates for Continental operated Bakken wells, averaging 2,300 Boe per day and 80% of the production was crude oil. In fact, 8 of Continental's best 30-day rate Bakken wells have been completed in the last two quarters. This is pretty amazing given we've been in the play for 15 years and completed over 1,600 operated wells. To date we have completed about 164 Bakken wells with what we call our optimized completion techniques. And on average, the results continue to align with the 1.1 million barrel equivalent type curve we announced last year for our optimized completions. Based on this type curve, rates of return have doubled to 140% and the PV-10 breakeven for our Bakken wells now stands at a remarkably low price of $28 per barrel. The Bakken differentials in the first quarter also continued to trend lower, coming in at $4.31 per barrel, which improved our netbacks 47% from the first quarter of 2017 and 8% sequentially. We expect our Bakken differentials to remain in this range throughout the year with some seasonal fluctuations. The improved differential is driven by added pipeline takeaway capacity and renegotiated contracts that lowered our transportation costs for dedicated barrels by about 40% to $3.75 per barrel. These dedicated barrels represent around 30% of our current Bakken production and are subject to a contract that became effective January 1, 2018 and expires October 2024. With over 4,000 operated wells in inventory, the future value to be realized by Continental and its shareholders from our Bakken assets is tremendous. To ensure we are maximizing returns and recoveries, our teams continue to work on further optimizing our Bakken completions and we'll keep you posted on the results. Let's look at some updates from our SCOOP and STACK assets in Oklahoma. And as Harold pointed out, we have begun drilling a massive oil project we call Project SpringBoard in SCOOP. Project SpringBoard is a multi-year multi-reservoir project with up to 400 million Boe of gross resource potential and 70% to 85% is expected to be oil. The project will be operated by Continental. It is approximately 70 square miles in size, covering almost 45,000 gross contiguous acres in Grady County. We anticipate that up to 350 wells will ultimately be drilled in the project, with around 100 targeting the Springer and 250 targeting the Woodford and Sycamore reservoirs. Continental will have an impressive 75% working interest in these wells on average. This project is the culmination of years of exploration, delineation drilling and strategic leasing and acquisitions. We couldn't be more pleased with the controlling position we have in this outstanding project. And I should add that as impressive as Project SpringBoard is, keep in mind it represents only 18% of our acres in SCOOP Springer and about 12% of our net reservoir acres in SCOOP Woodford and Sycamore. Our development of Project SpringBoard is currently broken into two phases. Phase 1 will focus on unit development of the Springer and Phase 2 will focus on unit development of the Woodford and Sycamore reservoirs. Phase 1 drilling is underway with three rigs drilling Springer wells, and we expect to have five rigs drilling Springer wells in the project by mid-year. A total of 29 Springer units will be systematically developed using row development strategies that will bring maximum efficiency to the project. A total of four rows will be developed with some rows reaching 9 miles wide. Our five rigs will complete one row at a time, walking from east to west and then return to the east and start the next row. Completion crews will follow behind the drilling activity. Now the efficiency gains we expect using row development strategies are tremendous. We believe drilling costs for a Springer well can be reduced by as much as $1 million per well while production from each pad could be accelerated by up to 19 days through zipper operations. Oil and natural gas gathering infrastructure that is in place or is scheduled to be put in place will further improve netbacks. Likewise, our SCOOP Springer barrels are highly profitable with differentials averaging below $2 per barrel, thanks to the close proximity to Cushing and local Oklahoma refiners that prefer this high-quality crude. Within Project SpringBoard, we elected to drill four Springer wells in the Triple H unit before officially kicking off row development. We did so to test our ability to drill extended laterals up to 10,200 feet long into thinner portions of the Springer reservoir. We are very pleased with the results because our teams not only stayed in the targeted intervals, but also drilled wells in 35 days on average, which is the same amount of time it took us to drill a 1-mile Springer well just 14 months ago. The bottom line is our teams drill the Triple H 2-mile laterals for the cost of a 1-mile well. We are also pleased with the early performance of the four Springer wells under Triple H unit. The four wells flowed at a maximum combined 24-hour rate of 6,065 Boe per day with average flowing casing pressures of around 2,100 PSI. Of note, 88% of the production was high quality 46-gravity crude, emphasizing the oil-rich nature of our Springer assets. We are also finishing up the drilling and completion of 12 additional wells in 4 Springer units in Garvin County before we focus our rigs on Phase 1 development in SpringBoard. These wells will be completed in the second quarter and continue to test stage length, proppant loads and long laterals to further guide and optimize future development of the Springer. Before leaving SCOOP, there is another significant development I need to mention. Well costs for Woodford oil wells going forward have been reduced by approximately $1 million. These savings are coming from our new well design that eliminates the need for an intermediate casing string, and in turn reduces the drilling days required to drill the wells. Our teams have done an excellent job experimenting with many wells and mapping out the pressure regimes to develop this new design. This is obviously a huge development as we have hundreds of Woodford oil wells ahead of us to drill. With this reduction in cost, our typical Woodford oil well now delivers a 70% rate of return and 70% to 80% of the production is oil. Now, let's move to STACK. We are making some strategic changes to further focus capital on our oil and liquids-rich assets. We are in the process of migrating three of our five rigs out of the SK JDA area as our de-risking HBP activity is nearly complete. Two of the rigs will move into the STACK Meramec over-pressured oil window and one will move into the SCOOP Woodford Sycamore condensate window. In total, we are deferring four gas wells and those are gross gas wells, and adding 11 gross over-pressured oil and condensate wells in 2018. Key point here is that with these moves 90% of our remaining 2018 drilling activity will be focused on oil and liquids-rich assets. We've also made a strategic move to provide flow assurance and access to premium markets for our SCOOP and STACK natural gas. As we announced last week, Continental has entered into a firm transportation agreement with Enable Midstream for 400 million cubic feet of gas per day of additional takeaway capacity through the Project Wildcat. Project Wildcat will move Continental STACK and SCOOP gas south to the Tolar Hub where demand for natural gas in the North Texas area is growing and production from the Barnett Shale is declining. Wildcat is expected to accommodate Continental's projected growth of natural gas and natural gas liquids for the foreseeable future, and is expected to begin taking gas in June and will be fully operational by July 2018. Project Wildcat is a great example of the proactive and collaborative approach we take to marketing our gas with our midstream entities. We do this not only in Oklahoma, but the Bakken as well to maintain flow assurance and add optionality to maximize the value of all of our products. I might add that to facilitate our growth, we have also installed strategically placed water recycling facilities and water gathering systems in SCOOP and STACK. In fact, we have more recycling facility capacity than any operator in Oklahoma. These facilities allow us to produce our wells in full capacity and not be constrained by third-party water handling infrastructure. Moving water and reusing these resources as much as possible is paramount to seal our success and offers many advantages to us as an operator as well as to the community and the environment. So, with that, I will turn the call over to John for more details on our performance.

[John D. Hart:]

Thank you, Jack. Good morning, everyone, and thank you for being with us today. We're off to a solid start for 2018 and in line with our expectations for full-year guidance. 2018 will be a breakout year in many aspects, but let me begin by focusing my initial comments on cash flow and liquidity, along with our continued commitment to reducing debt. In support of our previously stated near-term goal of reducing debt to $6 billion, we have reduced debt by $188 million while increasing our cash position to $98 million in the first quarter. Debt reduction was applied to the revolver, fully paying it off by quarter end. We expect to achieve our $6 billion target for debt in the second quarter or just around the quarter and we will continue working towards our longer term goal of $5 billion. As the revolver has now been paid off, further reductions will come by partial calls on the 2022 bonds. This will be in lot sizes yet to be determined and involve utilization of excess cash and revolver draws that will subsequently be paid down. You may recall that our 2018 guidance was for us to generate $800 million to $900 million in free cash flow at a $60 WTI during the year. However, as prices have strengthened even further, our estimate is now around $1 billion of free cash flow, assuming commodity prices continue to hold at or near the current levels. As you can see, this free cash flow combined with any potential divestiture proceeds should allow us to achieve even our long-term debt target of $5 billion in 2019. With our continued debt reduction combined with increasing EBITDAX, our first quarter annualized net debt-to-EBITDAX ratio was a much improved 1.73. Our current expectations are to be in the 1.5 range by the end of the year. Our efforts to reduce debt and improve our financial position have, in part, led to our recent improvement in debt ratings. In the first quarter, we were upgraded by both S&P and Moody's. The S&P upgrade is a return to investment grade where we believe we should be. In addition, just a couple of days ago, we received a public investment grade rating from Fitch. As we have noted before, the investment grade rating is important to us as a company. And now that we have two such ratings, we will continue to work on moving a few notches into the investment grade classification over time as our metrics continue to improve. Our recent efforts have also been recognized by our bank group, which has continued to be very supportive over the past few years during the downturn in commodity prices. In early April, we closed on a new five-year unsecured credit facility, an investment grade style facility, with terms essentially the same as the prior agreement. The new facility has a borrowing capacity up to $1.5 billion with the ability to upsize to $4 billion with lender consent. Note that with our commitment to reduce debt and to grow production while generating free cash flow, our need for revolver borrowings will generally be limited. Therefore, at our election, we chose to reduce commitments under the revolver to $1.5 billion from a previous $2.75 billion, allowing us to reduce commitment fees by as much as $4 million per year. Full details on this new agreement can be found in the 8-K that we filed on April 12. As I mentioned previously, we are off to a solid start for 2018 and in line with our expectations for full-year guidance. Revenue for the first quarter was a strong $1.1 billion. Net cash provided by operating activities was $886 million and EBITDAX was $876 million. Net income for the first quarter was strong at $234 million or $0.63 per diluted share, ahead of consensus. Adjusted to remove items typically excluded by the investment committee – community and published estimates, we posted an adjusted net income of $255 million or $0.68 per diluted share for the first quarter, well-ahead of consensus. This was driven by strong production, price realizations and cost efficiency. First quarter capital expenditures and production were both in line with our budget and guidance, non-acquisition capital expenditures were $596 million and production was 34% higher than the first quarter of 2017, at approximately 287.5 Boe per day. We hit the midpoint of our 285,000 to 290,000 Boe per day guidance, but otherwise would have exceeded our guidance if you include 5,000 Boe per day of weather impact, which was predominantly full. As expected, production was relatively flat with fourth quarter 2017 and it is expected to remain at similar levels of 285,000 to 290,000 Boe per day, until later in the second quarter, when production turns up nicely, as we start bringing large North Dakota pads and South infill projects online. As these projects come on line, production will ramp-up significantly in the second half of the year, like it did in 2017. With the 2018 exit rate expected to be in the 305,000 to 315,000 Boe per day range and providing year-over-year production growth of 17% to 24%. We are on track to achieve our goals. In addition, due to our strong performance in the first quarter, we continue to deliver strong rates of return and return on capital employed. Our return on capital employed is tracking near the high end of our original expectations for 2018 and is driven in part by our strong well performance and low operating cost. Overall, our selected first quarter cash costs were in line with guidance. G&A excluding equity comp was $1.25 per Boe. Production expense was impacted by several spells of bad weather in North Dakota. And although the fourth – first quarter was slightly above the guidance at $3.60, this is normal for this time of year due to seasonal impacts. And we expect that on a full year basis, we will be within our guidance range previously provided of $3 to $3.50. Production tax was an average of 7.6% in the first quarter at the low end of our annual guidance. Many of you are likely aware that Oklahoma recently passed legislation to increase the production severance rate to 5% on the first three years of production from wells in Oklahoma. Although that will increase taxes beginning in July of this year, we retain our current guidance range of 7.6% to 8%. Now I'd like to discuss our 2018 outlook in a little greater detail. To begin with, we're on track to achieve our targets. As a refresher, our capital budget for 2018 of $2.3 billion is expected to generate 17% to 24% annual production growth with strong positive cash flow after funding CapEx. The capital deployment will be fairly evenly split between the three remaining quarters with the exception of the second quarter being a bit higher. As noted, we remain unhedged on the oil side, allowing for full participation in prices. Remember the budget is cash neutral than average WTI in the low to mid 40s for the year. A lot of our cash flow to be generated there. Our 2019 outlook remains the same with current expectations for production to grow 15% to 20% year-over-year with a capital budget range of $2.5 billion to $ 2.8 billion while generating significant free cash flow comparable to 2018 projections. With that, we're ready to begin the Q&A section of the call and I'll turn it back over to the operator. Thank you.

[Operator:]

Thank you. And our first question comes from the line of Drew Venker with Morgan Stanley. Your line is now open.

[Drew Venker:]

Hi, everyone.

[Harold G. Hamm:]

Hi, Drew.

[Drew Venker:]

I want to start on the Bakken if we could, and maybe you guys could just talk about how completion designs are evolving or what you're doing to drive those much stronger results?

[Gary E. Gould:]

Yes. This is Gary Gould. We continue to test most of our designs with 60 stages right now. If you look at the 164 wells that we have out in our fit for type curve in the investor update, we're about – 50% of those are 40 stage and 50% are 60 stage. We like what we're seeing with 60 stage, but our teams continue to look at how we can maximize the rate of return from that project. And so, we will continue to look at various design mechanisms in order to maximize that rate of return, both looking at how we can increase the type curve, as well as how we can reduce cost.

[Drew Venker:]

Thanks, Gary. Just as one of your peers around you also are, I think, modifying their completion designs or their development style. Are you seeing much that your peers are doing differently that seems to be working for them well and significantly different from what you're doing?

[Gary E. Gould:]

We get a lot of information since we're the largest lease owner up in Bakken. And note that we get their information as well as ours. Our teams evaluate outside operated activity as well as our own as we make our decisions on how we maximize our rates of return. And we believe we're a leader in this category, testing not only stage length but also cluster spacing or entry points along the lateral. We're also doing limited entry perforating. So we look at a number of different design parameters and we believe we're the leader in this category.

[Drew Venker:]

Thanks again for that, Gary. Just – so, one follow-up, just on the financial side whether this is for Harold or for John. You guys talked about probably getting to 1.5 times leverage by the end of the year and additional free cash flow next year. You guys talked also about various uses of free cash flow that you can choose from. But John, in your prepared remarks, you talked about trying to go further into IG territory. So, can you just give us clarity about what you're thinking for use of free cash flow, is that debt pay-down first, and then – or is it maybe some mix of debt pay-down and other options?

[John D. Hart:]

With the two agencies, we're the entry level to IG. We'd like to be a couple more notches into that, provide some insulation, if you will, against macro market-type conditions, and I think it fits the profile of the company where we're growing into. So, as we push down to that $5 billion range, you're going to see a debt-to-EBITDA that's kind in the 1 to 1.25 type range that gives us a lot of flexibility to what we do. There's nothing to say when we get to $5 billion that we won't go lower than that. The bonds that I referenced, the 2022s, there's $2 billion outstanding on those. So, if we paid off all of those that would put us down in the low $4 billion. We paid off a portion of them that get us into the $5 billion. So, I think that's a good range, gives you a little sensitivity. That will be one of the considerations that we'll evaluate. What we want to do is as we've said in the past as we're – I think, we're unique as a company and that we can generate exceptionally strong production growth in some of the leading basins within a strong cash flow generation return focused mentality. And, we're going to balance those two so that might mean we put a little more cash into operations as we go forward. It might mean we pay debt down a little further. There's a lot of optionality within that. And it's a great position to be in and some great options that we have.

[Drew Venker:]

Thanks for the color, John.

[John D. Hart:]

Thank you.

[Harold G. Hamm:]

Thank you, Drew.

[Operator:]

Thank you. And our next question comes from the line of Doug Leggate with Bank of America. Your line is now open.

[Doug Leggate:]

Thanks, everybody. I got to kick off by saying what an amazing hire you guys made in Investor Relations. So, congrats to everybody. Joking aside – so I've got two questions. Jack, one for you. It's really more of a housekeeping question. You kind of slipped into the deck 4,000 Bakken locations. I'm assuming those are gross. What I'm really kind of getting at is that Tier 1, Tier 2 has kind of morphed into one very high quality area now it seems. So, can you give us an idea what is the real on a net basis running room that you see with the kind of production rates that you've – completion rates that you've seen, I guess, in the last – the last – what is it? 160 wells, I think, you're up to now?

[Jack H. Stark:]

Well, to make sure – I'm not sure. What's your question again on that? I mean...

[Doug Leggate:]

So, that you've got 4,000 locations declared. Is that a gross number or a net number? I'm just trying to get an idea what the running room is on the quality of these enhanced completions.

[Jack H. Stark:]

Sure. No, it's 4,000 gross operated locations. Okay. You need to know that. And so – and as far as running room is concerned, I mean, gosh, as I've mentioned in the past, I mean, if we were to put 8 to 10 rigs active in the Bakken, which we're at 6 right now, it'd take us 10 years to drill up half our inventory. And the quality of that inventory as far as rate of return on that blended average that we would have for that period time is in that 60% to 80% range – rate of return range. So, it's a great inventory and it continues to impress.

[Doug Leggate:]

Okay. So, I guess, the – I'll take the detail number offline. But just a quick add on to that, Jack, if I may. Looking at your completion certificates, electrical submersible pumps are kind of a regular feature of your wells. Is that a new thing or has it been a constant part of your development program in terms of boosting that initial production rate?

[Gary E. Gould:]

It's Gary Gould, and I can address that. It's about three quarters ago when we raised our type curve up to the 1,100 MBoe type curve. Yeah. And this is a big piece of increasing that type curve. We talked about how our EUR improved 12%, but our initial rates have doubled with that type curve. And a lot of that doubling of initial rate was with the application of ESPs that increased that initial rate. And those are important because we're completing with a lot more fluid, a lot more proppant. And so, it's providing more energy to these wells from the reservoir. And so, associated with these optimized completions, we applied optimized lift associate with the ESPs also.

[Doug Leggate:]

That's really helpful, Gary. Thank you. My follow-up is really just a quick one for John. John, the 57% to 60% oil cut always gets a lot of attention, I realize you had some weather impacts this quarter. But you've also switched the rig allocation, as you pointed out, towards more oil weighting going forward. So, does that change the 57% to 60% expectation on a go-forward basis? And I'll leave it there. Thanks.

[John D. Hart:]

Do you want it?

[Harold G. Hamm:]

Go ahead, John.

[John D. Hart:]

I think that is a good range, that's driven primarily by the timing of when pads come on. I think, as you go through the balance of the year, you'll see oil production rising. It would've been higher this quarter, not only in terms of volumes, but in terms of just percent of total production absent the weather. So, that is a fair point. The shift in the rig activity, a lot of that will come on because it's on pads, big pads, a lot of it's down in Project SpringBoard or some of it is, and some of it's up in STACK. You'll see those coming on later in the year, so you'll see a little bit of an uptick from them later in the year, and you'll see an exceptional one right at the beginning of 2019.

[Harold G. Hamm:]

So, a good question, Doug. Overall, I mean basically this shift to liquids and oil at this time, it definitely – you'll see an impact this year towards the end of the year, as John said, and again in 2019.

[Doug Leggate:]

Great stuff. Thanks, everybody.

[John D. Hart:]

Thanks, Doug.

[Operator:]

Thank you. And our next question comes from the line of Neal Dingmann with SunTrust. Your line is now open.

[Neal D. Dingmann:]

Good morning, guys.

[Harold G. Hamm:]

Hey, Neal.

[Neal D. Dingmann:]

Jack, maybe a question for you guys, obviously, the potential for the SpringBoard on that 31,000 in gray just looks immense. And I'm just wondering, what other areas and will you expand that once you develop and start sort of process – I know it's very early and you're just sort of getting going in here, but I'm wondering, besides this 31,000 acres, is there prospectivity for this elsewhere?

[Jack H. Stark:]

I'm glad you asked that question because we do, we have another project of pretty much similar size and scale and working interest that would be teed up after this.

[Neal D. Dingmann:]

Oh, very good. In sort of the same – general and that's sort of same general SCOOP area?

[Jack H. Stark:]

Yes it is in SCOOP.

[Neal D. Dingmann:]

Got it. And then, just lastly up in the STACK. You've been adding some rigs elsewhere, just if you could comment there, any expansion or anything that you'll be ramping up in that area?

[Jack H. Stark:]

In the STACK area?

[Neal D. Dingmann:]

Yes, sir.

[Jack H. Stark:]

Yeah. In STACK what we're doing is we're moving rigs over into the – out of the gas window into the oil, and so, we've got 10 density projects we're targeting right now with these rigs. And really, we'll have seven rigs drilling up in STACK, two will be in the gas, but the other five will be over here essentially developing our oil window units. And probably in there, I think, we've got 1 out of the 10 I'm talking about is in the condensate window.

[Neal D. Dingmann:]

Thank you. Outstanding quarter, guys.

[Harold G. Hamm:]

Thank you.

[Jack H. Stark:]

Thank you.

[John D. Hart:]

Thank you.

[Operator:]

Thank you. And our next question comes from the line of Brian Corales with Johnson Rice. Your line is now open.

[Brian Corales:]

Good morning, guys. Just a couple questions on the SpringBoard. How should we think about? Is this just kind of like just mowing the lawn, you're going to – I'm assuming two or four well pads across the acreage, and then once you get a certain amount, you'll just start the completion crews behind them? Is that the way to think about it?

[Jack H. Stark:]

Well, you know it's a great way to put it, Brian. I like that. But it is. It is a – basically, it's oil manufacturing project and we're starting with the Springer and we'll work down into the Woodfords and in Sycamore. And we are taking this in row developments going East to West, as we – as I described. And one of the rows is up to nine miles wide. So, we've got a pretty big yard to mow out here.

[Brian Corales:]

Yeah. I would say so. And then I also noticed the Sycamore it was listed kind of at 70% oil. I just seemed to remember the Sycamore being much more gassy, and I'm assuming it migrates – so the oil maybe more to the East. How much more of the acreage is that oily for the Sycamore?

[Jack H. Stark:]

You know, I would say, you could probably – say, probably double that for the Sycamore, just ballpark-ish for oil window type acreage, and then the rest would transition into the condensate. That's really – you'll find that the Sycamore will pretty much mimic what the Woodford windows are looking like, so...

[Brian Corales:]

Okay.

[Jack H. Stark:]

And in this area we're looking at Woodford and Sycamore both being highly and very oil-rich. We're going to have to see anywhere from 60% to 80% oil in this because it is a transitional area. And a key thing here is keep in mind this is the area where we're actually going to be able to reduce our cost of drilling Woodford well by a $1 million. And there our teams came in and have laid out just a beautiful picture of what it takes to do that and how we accomplish this and it's been basically tested and it's – we're ready to basically implement that type of drilling design going forward and so it's – so this area Project SpringBoard takes advantage of that $1 million reduction in what it takes to drill a Woodford well. And also if you noticed in my comments too, we also see our ability to reduce our cost for drilling a Springer well by about a $1 million just because of the efficiencies of that row development. And so we're going to be able to really drive the cost down and increase the efficiencies like never before in Project SpringBoard from a drilling and completion standpoint. And on top of that, the infrastructure that we're going to be putting in there for gathering and distributing water and – are basically going to be there and be able to be used as we move into development of Woodford and Sycamore. So, there's just compounding efficiency gains that will continue to be developed in this project that will just increase the value of the resource we've got there.

[Brian Corales:]

Thanks, guys. If I could squeeze one more in, I know you just increased your type curve I think last year for the Bakken. Recent wells both by you and industry right now has been kind of eye-opening. What – if you're going to guess on a – recent – an EUR for some of your more recent wells, could you do that now or?

[Jack H. Stark:]

Well, I'll let Gary – yeah, I'll tell you right now I'm comfortable with the 1.1, but see upside to that and we just need to get more wells behind us to get comfortable with that. And it's just – it's what we're working on right now. And Gary?

[Gary E. Gould:]

Yeah. My comment is just if you looked at the last two years or so of results that we have and are matching very closely to that 1,100 MBoe type curve and so that's the confidence I have just by looking at that match.

[Brian Corales:]

All right, guys. Thank you.

[Harold G. Hamm:]

Thank you.

[Jack H. Stark:]

Thanks, Brian.

[Operator:]

Thank you. And our next question comes from the line of Bob Morris with Citi. Your line is now open.

[Robert Scott Morris:]

Thank you. Jack, on the SpringBoard, I just want to try and understand a little bit better the cadence of how you bring these wells online. I know, you said the wells take 35 days to drill and you'll have five rigs running here. So, is it that you'll bring four wells on a pad on at a time so that we have four wells coming on every 60 days or sort of how is that going to run as far as what wells come on, on what sequence, how is that going to be, how is that development going to go?

[Jack H. Stark:]

Yeah. What we're going to have is we're going to have five rigs. We got three drilling now, we'll have five drilling by June and we're going to drill the first two units. And as we move into the third unit, these are side-by-side two-mile units, the stim crews will move in. And so, we expect that we'll start looking at the stim work and getting first production out there kind of in that August timeframe. And so, that's really – it's really – once that happens, then they can go along simultaneously, with the rigs staying far enough out in front of the stim crews to where we don't have overlap and any kind of issues in that operationally. And as the rigs move to the very west edge of a road, they'll move back east, and the stim crews will essentially finish up that first row, and then turn right around and come back to the second row and follow the rigs again. So, it is truly, as Brian said, it's kind of like mowing the yard and it just – you'll have probably this – those rigs will essentially mow it and the stim crews will come and sweep it up.

[Robert Scott Morris:]

Okay. Sorry, just trying to – do you have a batch well that'll come on every 30 days or will there be a batch every 90 days or how do those come online?

[Jack H. Stark:]

Roughly probably about every two months. Yes.

[Robert Scott Morris:]

Every two months, okay. And then just real quick here. It looked like you – since your last presentation added 15,000 net acres in the STACK. Where exactly was that added?

[Steven K. Owen:]

Yeah. This is Steve Owen. I can't really tell you where it was. It's in STACK. It's a result of continued acquisitions from industry partners, as well as on the ground leasing. Between STACK and SCOOP, we consummated over 45 acquisitions this quarter, and we continue to be aggressive in our acquisitions.

[Robert Scott Morris:]

Okay. Great. Thank you.

[Harold G. Hamm:]

You bet.

[Operator:]

Thank you. And our next question comes from the line of Brian Singer with Goldman Sachs. Your line is now open.

[Brian Singer:]

Thank you. Good morning.

[Harold G. Hamm:]

Hey.

[Jack H. Stark:]

Hi, Brian.

[Brian Singer:]

Given the favorable operational performance and cash flow, do you see limitations at all by other facilities or acreage or eroding efficiencies that would keep you from increasing activity in the Bakken or in SCOOP, STACK in aggregate, or is that the choice to focus on debt pay-down really solely discipline on your part?

[Gary E. Gould:]

This is Gary Gould and that focus on the debt pay-down is purely from discipline. We have a very high quality inventory, very high quality operations team such that we can grow at a balance of whatever rate we want. And in considering how much we want to also at the same time pay down our debt. So, those are the drivers. I might add that we have very good relationships with our service companies including our midstream providers where we are constantly communicating with them on our production forecasts and activity in all of our plays, and we don't see any challenges to produce. It's all about how much do we want invest in growth versus how much do we want to pay down our debt.

[Brian Singer:]

Great. Thanks. And a follow-up actually is on the midstream in part. Noted the incremental transport to get – just to move gas out of SCOOP and STACK at the same time. And probably unrelated, also noted the shift away from some of the gassier areas within STACK from a rig count perspective. Can you just talk about the production mix that you're seeing within STACK and SCOOP and whether there are any changes especially over the well's life relative to your expectations?

[Harold G. Hamm:]

I'll take that on. I think, we're seeing exceptional wells. These are the best wells like we've said up there that we've ever drilled. And, certainly, the shift is just to maximize value today and I feel we can do that because we've got such a great APP position with legacy production and just allows us this optionality to do this. So, we're very proud of this new transport capacity. This is going to be just exactly what we need, but we have the optionality to make that move.

[Brian Singer:]

Great. Thank you.

[Harold G. Hamm:]

Thanks, Brian.

[Operator:]

Thank you. And our next question comes from the line of Park Carrere with Howard Weil. Your line is now open.

[Park Carrere:]

Hey. Good morning, guys. Thanks for taking my question. With the increased efficiencies and kind of well cost reductions you're seeing from the SpringBoard, does that maybe change the way you look at down-spacing through that maximum PV-10? Is there may be a round of down-spacing even further?

[Gary E. Gould:]

This is Gary Gould, and we'll continue to look at that. You're right. I mean every piece of the economic model is important in determining what that optimum is. We've done enough testing so far that we believe that four wells is optimum. As you probably know, we were one of the first ones to come out with describing how we look at maximizing value through – in a development such as is on slide 17 for the Springer, and so right now we still believe it's that four wells on average pretty good.

[Park Carrere:]

Okay. And kind of – I may have missed it. Did you talk about maybe why your decision to locate it where you did in the SCOOP, and then is this something that's applicable to your other basins?

[Jack H. Stark:]

You're talking about Project SpringBoard.

[Park Carrere:]

Yes.

[Jack H. Stark:]

Yeah. Well, it's geology driven. I mean, we got in there, and I mean, you go where the resource is. And as Harold said in his comments this project has been years in the making and it took – its grassroots exploration through leasing and acquisition and delineation drilling has gotten us to this point. And so, it's again the reason we have this project here is because of geology, and I'll also add that the geology – this year you're looking at STACK reservoirs. And as I mentioned we have about 70-square mile project and we have another project in that SCOOP area of about equal size and magnitude. So, it isn't just one opportunity. It's – there's multiple opportunities for this type of program.

[Park Carrere:]

Is there any point to – sorry go ahead.

[Harold G. Hamm:]

Yeah. This reservoir didn't produce there within this area. We – our geologists identified it and we delineate it, tested it, and did that first vertically as I said, and then knew that it would be a great producer horizontally and it was. So, the big difference was because it didn't produce widespread, it was able to acquire it, and now we just own this area. So, it's a great project.

[Park Carrere:]

Okay. Great. So, there's no line of sight that maybe trying this in the Bakken, or the STACK at this time?

[Harold G. Hamm:]

Where you have this, where you have the rock. The STACK determines it.

[Jack H. Stark:]

Exactly. And there will be some other areas. I'd tell you there's uphole zones out here yet to be defined. With that, we'll be adding to the STACK so to speak of reservoirs that will produce in these areas, and so, there will be other areas where we have uphole zones relative to the Woodford that we probably would combine with development of Woodford and Sycamore.

[Park Carrere:]

Great.

[Harold G. Hamm:]

Absolutely.

[Park Carrere:]

Brilliant.

[Harold G. Hamm:]

Yeah.

[Park Carrere:]

I really appreciate the time. Thanks for the questions – and taking my questions.

[Harold G. Hamm:]

Yes.

[Operator:]

Thank you. And our next question comes from the line of Brad Heffern with RBC Capital Markets. Your line is now open.

[Brad Heffern:]

Hey. Good morning, everyone.

[Harold G. Hamm:]

Good morning.

[Jack H. Stark:]

Good morning.

[Brad Heffern:]

A question on the Bakken. There's been a lot of talk about gas processing capacity in the basin especially as it relates to sort of the capture requirements that the state has. So, any thoughts on how you, guys, are positioned as it relates to gas processing?

[Gary E. Gould:]

Yes. This is Gary Gould. We've been a leader in the Bakken in terms of gas capture for many, many years now. If you look at the last 12 months in the Bakken pool, our average gas capture is 89% which is well above the current 85%, let alone the 88% requirement that's coming up in November. And so as we've mentioned earlier, we talk to our midstream partners all the time and providing forecasts for where we're going. And those midstream companies are committed to investing the CapEx and providing the opportunity for us being able to deliver on our forecast, which includes delivering on our guidance that we've already given.

[Brad Heffern:]

Okay. Thanks for that. And then you guys have talked in the past about having some decent size asset sale packages out there, but at the same time, obviously, you're generating a lot of cash. And so is there still a desire to do asset sales or have you pulled back on that?

[Gary E. Gould:]

We're still working them. We've got a number of things coming and hope to have something for you soon. But it's active, and we've done a number of smaller ones and we're working on a number of others. So it continues to be part of it.

[Brad Heffern:]

Okay. We'll stay tuned. Thanks.

[Harold G. Hamm:]

Thank you.

[Operator:]

Thank you. And our next question comes from the line of Arun Jayaram with JPMorgan. Your line is now open.

[Arun Jayaram:]

Yeah. Good morning. Just a quick question. As you shift to these large-scale manufacturing projects like you're doing at SpringBoard and the SCOOP to optimize returns and efficiencies, how should we think about infrastructure CapEx as you move to these types of developments? Does it change the cadence of that? Or I want to see if you can give us a little color on that?

[Gary E. Gould:]

This is Gary Gould again. And when it comes to infrastructure, we are already heavily invested in projects that are providing good economic returns for us. So whether it's in Oklahoma where I believe we have the largest recycling facilities in the state or whether it's in North Dakota, where we have significant water gathering and SWD systems also. We're really already invested in them because we have such concentrated operations. We're a leading producer both in North Dakota and in Oklahoma. What that means is we've got concentrated operating positions that allow for that type of investment. And we already have most of that infrastructure already in place.

[Arun Jayaram:]

Interesting. Thanks for that. And then just – not trying to nitpick here. You guys talked about record performance in the Bakken in the quarter. Just looking from your commentary, last quarter you talked about how your optimized wells were slightly outperforming the type curve and now you're in line. Just maybe trying to understand a little bit behind that, are you drilling more wells outside of the core or just a little bit about the change in language in the press release.

[Gary E. Gould:]

Well, I don't think there's really any major change in the language. That's my opinion. And I'd say...

[Arun Jayaram:]

Okay.

[Gary E. Gould:]

...I'd point to a couple different things. One is that these Bakken completions are working everywhere. They're uplifting the results everywhere, whatever someone considers the core and we can tell because we watch what other operators are doing in their areas outside of ours. And then second, as far as results go, if you look at our table that we have in our investor update, what you'll see is our top eight wells of all-time for Bakken based on 30-day rates occurred over the last two quarters. So we continue to generate great results.

[Arun Jayaram:]

Yeah.

[Jack H. Stark:]

And this is Jack. If you look at page 28, you can see that Bakken production from these wells. And I'll just mention that, again, you can kind of look at that and go, I see a slight outperformance there. And so it's just language. I mean, we...

[Arun Jayaram:]

Yeah.

[Jack H. Stark:]

...it was not intended to message anything because these wells are performing just as we've described and are expecting.

[Arun Jayaram:]

Yeah. I wasn't trying to nitpick. I just wanted to understand that. So appreciate it.

[Jack H. Stark:]

You bet.

[Harold G. Hamm:]

Thanks, Arun.

[Operator:]

Thank you. And our next question comes from the line of Leo Mariani with Nat Alliance Securities. Your line is now open.

[Leo P. Mariani:]

Yeah. Hey, guys. I was hoping you could give us maybe a little guidance on the new transportation expense line item that sort of worked its way in this quarter. I know there was an accounting change, which is kind of forcing you guys to sort of show this. But just trying to get a sense of if this is going to be kind of a per BOE expense that we should expect going forward, or is there any kind of guidance you can sort of give on that?

[John D. Hart:]

You're right. It is an accounting change. It's driven by the new revenue recognition standards that are out there. And what they require is that for inside operated production, we show transportation expense as a separate line item. Previously they were netted into revenue. Outside operated transportation still remains netted into revenue because we don't have those numbers, and it's a little awkward but that's the way the standard is written. That's something we'll work to give you guidance on going forward. It really kind of depends. The per BOE is probably a reasonable way to look at it now. It will vary depending on what our production allocation is and where we're at. But for now, I think that's probably a reasonable way to look at it. I want to point out the key thing is your bottom line, your net income is not any different. Now, when we talk about it like in MD&A, because outside and inside operated are different, we're going to throw that back up into revenue as a pro forma so you can see it within the differential. We've got all of that included in our differential guidance. So our guidance for it today is already within the differential. So if you add it as a separate item in your model, you're probably going to be overstating because, like I said, it's included in what we're guiding you on the commodity differential.

[Leo P. Mariani:]

Okay. That's helpful for sure. And certainly realize that there's been some moving pieces in terms of well performance. Obviously, you guys were able to drive well costs down in the SCOOP oil play. You've had some very good success in the Springer. And, obviously, your traditional Bakken continues to hum along. I was hoping you guys could maybe rank the portfolio in terms of returns as you sort of see it on the oily plays here during the course of this year.

[John D. Hart:]

As far as ranking, I mean, you're looking at 180%-plus type returns in the Springer. You're looking at 140% in the Bakken, 70% in Woodford Oil. I mean they're all – and the thing is these plays you're looking at 80% – return of 80% oil on these. So they're extremely oily-rich projects. And, quite frankly, it's a great portfolio to be able to mix and match and be able to just kind of balance out our activity levels and on our operations. And so as far as ranking them, you could just take them straight on rate of return, but when it comes down on allocating rigs, there's a lot other things go into it before then just that.

[Jack H. Stark:]

They're exceptional.

[John D. Hart:]

They're just...

[Leo P. Mariani:]

Okay. Very helpful there. I guess, obviously, you guys mentioned that you had some HBP requirements to finish up here in 2018. Now it's allowing you to shift some of the rigs away from the gassier areas. Just as I think forward into the next couple of years, will you have to kind of shift back a little towards some gas stuff to hold acreage or are you sort of done with that and you can kind of continue to plow ahead with SpringBoard-type initiatives over the next few years?

[Harold G. Hamm:]

Yeah. We're winding up in the JDA with our HBP acreage, and so we can dial that back to about two rigs for the balance of this year and hold that. And Steve, you've got anything to add there?

[Steven K. Owen:]

Yes, sir. To your point, we're over 90% HBP in the SK JDA area.

[Harold G. Hamm:]

So I think we can hold pretty flat with that rig count for right now.

[Leo P. Mariani:]

All right. That's helpful. Thanks.

[Harold G. Hamm:]

Yeah. Thank you.

[Operator:]

Thank you. And our next question comes from the line of Derrick Whitfield with Stifel Financial. Your line is now open.

[Derrick Whitfield:]

Good afternoon, all.

[Harold G. Hamm:]

Hello.

[Derrick Whitfield:]

As you guys are aware, both oil and gas marketing has become quite an important topic throughout earnings. Referencing slide 21, could you speak to your views on how Permian gas could impact the markets you're selling to at present? And finally, if you could comment on what degree of exposure you have to in-basin pricing in the Anadarko?

[Harold G. Hamm:]

Well, that's the beauty part of the line that we just announced, the fact that we're taking it out of the basin here. So basically it limits our exposure. Ramiro, you want to add, too?

[Ramiro F. Rangel:]

This is Ramiro Rangel. Yes, the Permian gas has really been hampered by lack of infrastructure and this project really helps us to be able to access some premium market. So we are in a very advantaged position. So we really like where we're positioned right now.

[Derrick Whitfield:]

Got it. And then maybe switching gears, circling back to the STACK acreage, could you guys provide the revised acreage splits by phase window?

[Harold G. Hamm:]

In STACK?

[Derrick Whitfield:]

That is correct.

[Harold G. Hamm:]

Do you have those, Tony, those numbers?

[Tony Barrett:]

Yeah. I sure do. This is Tony Barrett. As we sit right now on our existing leasehold, about 30% of our assets are in the oil window, around 25% in the condensate window, and about 45% in the gas window.

[Derrick Whitfield:]

Got it. And one last question if I could. So regarding the design modification you guys talked about in the SCOOP oil trend, are there other potential applications across the STACK or SCOOP or said differently, are you guys testing other concepts that could reduce costs at present?

[Gary E. Gould:]

It's Gary Gould. And I would just say that our teams are constantly looking at how to lower our drilling and completion costs and optimize our economics in order to maximize that rate of return. And if you look at our drilling team, Continental has been a leader in horizontal drilling for over two decades, well before even these shale plays came along, and that drilling team continues. And, yeah, here Harold just calls it big boy drilling in Oklahoma and in the Bakken. And so our teams continue to reduce cost. It's amazing how fast that our Bakken team is drilling wells, and then our drilling teams will continue to find efficiencies on how to drill these multiple targets that we have in the Anadarko Basin as well.

[Derrick Whitfield:]

Very helpful, Gary. Thanks.

[Harold G. Hamm:]

Thank you.

[Operator:]

Thank you. And our next question comes from the line of Marshall Carver with Heikkinen Energy. Your line is now open.

[Marshall Hampton Carver:]

Yeah. Thank you. Most of my questions were answered, but I did have a question. With regards to the switch of the STACK rigs from the JV to more oily wells and also with the SpringBoard project, were those part of your 2018 plan all along or is that a shift to the greater oiliness versus the original plan from around year-end?

[Harold G. Hamm:]

No. These changes are basically the allocation of rigs in STACK were – this is a change. And so what we'll ultimately see is probably about 11 gross oil wells were drilled and completed up there in the SCOOP and STACK, or excuse me, in the – I guess in Oklahoma and four less gross gas wells. So there is that change and that isn't really represented in our budget. So what that says is, obviously, we're going to be moving to a more oily mix.

[Marshall Hampton Carver:]

Okay. That's helpful. Thank you. And any signs of inflation in either the Bakken or the SCOOP/STACK?

[Gary E. Gould:]

This is Gary Gould. You may remember that we included about a 5% to 10% inflation in our budget earlier in the year, and we're just still on target as far as meeting that type of budget performance. What we see is really a lot more stim horsepower coming into the market with this increased demand that we have. We also have increased supply. And in addition to that, like on the drilling side, we also have rigs that are continuing to come off term contracts, which are going to lower our cost of doing business on the drilling side. So we can see some reductions in costs, both from the drilling and completion side when we think about those type of opportunities.

[Marshall Hampton Carver:]

Okay. Thank you. And then you talked about the savings at Springer in terms of well cost with SpringBoard. Where would that put anticipated well cost for the Springer in that play?

[Gary E. Gould:]

Yeah. Well, that's what we're going to do is we're going be watching these costs as we go into this Project SpringBoard. That's what we see right now. And so we'll report more on that probably in the next quarter.

[Marshall Hampton Carver:]

Okay. Thank you very much.

[Harold G. Hamm:]

Thank you.

[Operator:]

Thank you. And our next question comes from the line of David Beard with Coker & Palmer. Your line is now open.

[David Earl Beard:]

Good morning, everybody, and thanks for taking my call here. I know we've run over, so I'll make it quick. I'm going to throw a little geographical curve ball at you. Can you talk at all about the Delaware Basin in Northern Delaware? Boots on the ground tell me you might be looking at that play. Do you care to comment on that at all? Thanks.

[Tony Barrett:]

Hi. This is Tony Barrett. I mean, of course, as you well know, we're an exploration company and we're always out looking for new opportunities for Continental and our shareholders. As usual, we typically don't report on any of our projects until we have a result. So at this time, I don't have a result to give you, but we will as soon as we get one.

[David Earl Beard:]

Totally understand. Thanks for the time and good luck for the rest of the year.

[Tony Barrett:]

Yeah. Thank you.

[Harold G. Hamm:]

Thank you, David.

[Operator:]

Thank you. And our next question comes from the line of Harry Mateer with Barclays. Your line is now open.

[Harry Mateer:]

Yeah, thanks. John, just to confirm your comments re the 2022s. So it sounds like at this point you have no intention of tapping the investment-grade bond market to fund those calls and you're just going to do some smaller partial calls in each of the next few quarters and draw the revolver where necessary as a bridge. Is that right?

[John D. Hart:]

That's correct.

[Harry Mateer:]

Okay. And then press release last night seemed to talk about net debt, but I just want to confirm the $5 billion target you have is gross debt, not net debt. Is that right?

[John D. Hart:]

That is correct. It's gross debt. The net debt is just meant to communicate, look, we've got a lot more cash than what we've traditionally had. We had $98 million at the end of the first quarter. We had mid-$40s million at the end of the year. So we grew cash a lot while we paid off $188 million. So if you look at it from that perspective, our debt's even lower than the absolute. We're just trying to factor that in. Our targets are based on gross debt, and we're well on track.

[Harry Mateer:]

Got it. Thank you. That's very clear.

[John D. Hart:]

Thank you.

[Operator:]

Thank you. And that concludes our question-and-answer session for today. So, with that, I'd like to turn the call back over to Vice President of Investor Relations, Rory Sabino for closing remarks.

[Rory R. Sabino:]

Great. Just wanted to thank everyone for joining us today. If you have any further questions, please reach out and have a great day. That concludes the call.

[Harold G. Hamm:]

Thank you.

[Operator:]

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