Continental Resources, Inc.
Q1 2017 Earnings Call Transcript

Published: 4 May 2017

[Operator:]

Good day, ladies and gentlemen, and welcome to the Continental Resources First Quarter 2017 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, this conference call is being recorded. I would now like to introduce your host for today's conference, Mr. Warren Henry, Vice President of Investors Relations. Sir, you may begin.

[Warren Henry:]

Thank you, and thanks everyone for joining us this morning. I would like to welcome you to today's earnings call for Continental will start today 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 other senior members of the Executive Management team including Jeff Hume, Vice Chairman of Strategic Growth Initiatives; Tony Barrett, Vice President, Exploration; Pat Bent, Senior Vice President Drilling; Gary Gould, SVP Production and Resource Development; Steve Owen, SVP Land; Ramiro Rangel, SVP Marketing. We are also pleased to introduce our new Chief Operating Officer this morning Tony Maranto, who just joined the team next week. Tony comes to Continental with over 35 years' experience, including 20 years with EOG where he last served as Vice President and General Manager of EOG's Mid-Continent business unit. Tony will be overseeing operations and will report to Jack. Welcome to Continental Tony. Today's call will contain forward-looking statements that address projections, assumptions and guidance. Actual results may differ materially from those contained in forward-looking statements. Please refer to the Company's filings with the Securities and Exchange Commission for additional information concerning these statements and risks. In addition, Continental does not undertake any obligation in the future to update forward-looking statements made on this call. Also in this call, we will refer to initial production levels for new wells, which in most cases are maximum 24-hour initial test rates. 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 those items covered, I will now turn the call over to Mr. Hamm. Harold?

[Harold Hamm:]

Thank you, Warren, and good morning, everyone. Continental's most to celebrate this year and we start off with an excellent first quarter where ahead on production and earnings. On CapEx I expect and year at the top of our guidance. In 2017 marks the 50th anniversary of the Continental. This anniversary of minds made the Continental outstanding portfolio of assets has been 50 years in the making. Thanks to ingenuity, skill and doesn't work for employees over the years. Continental now controls more than 2 million Net Reservoir Acres and decades of drilling inventory and the top place in the United States. Approximately 70% of those acres are held by production and secured for future developments. As shareholders and potential shareholders and you have the opportunity to benefit from this history as we harvest and grow these assets with advancing technologies to realize their full potential. Results we will share with you this morning provide just a glance of the remarkable potential relies ahead for Continental and its shareholders. Jack will provide details on our first quarter operating results, but I would like to highlight four aspects of Continental's growth strategy that are especially critical in today's market environment. First Continental is increasing the value of it premier asset, quality matters and we are magnifying the value of our strategic positions. The Bakken, SCOOP and STACK continue to improve as we optimize completion designs. These assets generates exceptionally strong rate of return in today's pricing environment. Bottom line quality assets combined with optimized completion translates directly into more barrels of oil per dollar invested on our plays. Second, we continue to focus on operating and capital spending discipline. The magnitude and pace of our operations is dependent on market conditions. Our operations generate positive cash in the first quarter and having debt reduction of 70 million of operating cost in line and non-acquisition capital expenditure below budget. Third, we are saying outstanding results as we work down our uncompleted well in Bakken. Well economics will improve as traditional markets become available with new pipeline takeaway capacity in the region. Industry-wide throughout the basin, we are already seeing approximately $2 per barrel increase in wellhead netbacks. Fourth and finally looking beyond the current volatility in daily markets, we have a long-term vision of world oil markets continuing to rebalance as inventories of oil are drawn down in response to restricted OPEC production, which together point to strength at oil prices. I just returned from the Divide Energy Conference and the conversations with other energy leaders confirm my belief that we are entering a new market regime and stable growth in world supply and demand. The United States has retaken its place as the world energy leader and we will compete effectively in this new regime. After Continental, we have tons of work prior to drive our production growth and higher value for shareholders in 2017 and beyond. It's been a great 50 years and today we're well positioned for the next several decades. Thank you again for your support. With that, I will turn the call over to Jeff.

[Jeff Hume:]

Thank you, Harold, and good morning, everyone and thanks for joining our call. As Harold pointed out, we continue to grow the value of our assets and unlock their true potential through technology and ongoing exploration. Through technology we are growing value by improving well performance and developing operational efficiencies that are increasing rates of return in all of our place. A great example is the tremendous performance uplift we're getting from our Bakken in SCOOP Springer wells through advanced stimulation technology. In the Bakken, our optimized completions are proving to be a real game changer. These optimized completions include various combinations of increased proppant per foot, tighter stage spacing, diverters more aggressive flow back in high volume lift technology. We call them optimized completions because they are specifically designed to maximize the value of each spacing unit. One size does not fit all in the combination - the completions themselves must be designed to optimize the performance of the unit based on the unique geological and mechanical conditions of that unit, although, the designs will vary. We have consistently seen significant production uplifts from these completions. Last quarter, we announced the results of seven optimized Bakken completions. These seven operator wells continue to be outstanding producers and in the first 150 days these wells have outperformed our 980 MBoe type curve by an average of 55%. This quarter we added another 16 optimized Bakken completions. 14 of these had over 30 days of production and all 14 are outperforming our 980 MBoe type curve at an average of 65% in the first 30 days. Both these wells delivered record 30-day rates for continental Bakken wells averaging 1,700 Boe per day during their first 30 days. This performance is very encouraging and indicates that our optimized completion are uplifting EUR as well. Just how much remains to be seen. We need more production history from these recent wells to determine how much of the performance is acceleration and how much is added EUR. Regardless these optimized completions are doing exactly what we want them to do and that is to maximize returns on our investment. The rate of return on these optimized Bakken wells has nearly doubled to an expected average of 75% as compared to the 40% rate of return we originally projected for 2017 drilling program assuming $7 million complete well cost and $55 WTI. Our structural drilling efficiencies in the Bakken continue to contribute to the bottom line as well. Spud to TD times in the first quarter averaged 12 days down 16% from our average in 2016 and 31% below our 2014 average. Total completed well costs for our Bakken wells in the first quarter came in right around our projected cost of $7 million. We currently have four operated rigs drilling in the Bakken and plan to maintain that level through year end. We also have seven simulation crews working down our uncompleted well inventory which at the end of the first quarter was around 200 wells. This includes 170 of the docks that remained at year end 2016 and 30 new wells from our 2017 drilling activity. We plan to add an eight stim crews this month and our ninth stim crew by midyear to accelerate our completion activity. Now let's move on to SCOOP where technology is also raising the bar based on the outstanding performance we are seeing from the first three Springer wells we completed this year. These include the Cash, Trammell and Strassle wells which are also the first Springer wells we have completed since the third quarter of 2015. All three are excellent producers and are outperforming a long standing 940 MBoe type curve 4,500 foot lateral. The Cash well was designed to compare the impact of current stimulation technology on a traditional 4,500 foot lateral Springer well. The Trammel Strassle wells were designed to evaluate the impact of both longer laterals and current completion technology. All three Springer wells were stimulated with increased proppant volumes per foot and tighter stage facings relative to previous Springer wells. The performance of the Cash well has been outstanding as you can see on Slide 11 in our slide deck on the Continental website. We came on flowing about 1,700 Boe per day at 2,000 psi flowing casing pressure and 84% of the production was oil. In the first 30 days the Cash well has outperformed our 940 MBoe type curve by 75%. We currently estimate of what will pay out in nine months. The Cash was also drilled in record time, 34 days from spud-to-TD. This is a 45% reduction drilling days and 33% reduction in drilling cost compared to similar Springer wells we drilled in the third quarter of 2015. Total completed well cost for the cash came in at approximately $7.6 million down approximately 25% from our average completed well cost in the third quarter 2015. The Trammel which was an 8,300 foot lateral came on flowing at an impressive rate of 2,300 barrels of oil per day - Boe per day, at 3,300 CSI flowing casing pressure in 79% oil. This is both a record initial rate and record lateral length, Springer well for the Company. During its first 60 days, the Trammel performed a 940 MBoe type curve by 100%. Lastly, the Strassle well was drilled with 5,800 foot lateral and produced 1,250 Boe per day, at 1,500 psi flowing casing pressure and 89% of the production was oil. At 60 days this Strassle outperformed the 940 MBoe type curve by 35%. We now intend to keep one to two rigs active in the Springer of two year and expect we could add another five Springer completions during the year. In addition to adding value through technology, we continue to compound the value of our assets the respiration and establishing new reservoirs. As we pointed out in the past, SCOOP and STACK are part of the Woodford petroleum system that contains multiple stacked reservoirs. The USGS defines it as the over-pressured Anadarko mega compartment that reaches up to 5,000 feet thick. This over-pressure mega compartment stretches for almost 200 miles from the north end of STACK, to the south end of SCOOP. In 2012, we announced the SCOOP wooden play. In 2014 we announced the SCOOP Springer play. In 2015 we announced our first STACK Meramec well. And today we're announcing that under our existing leasehold in SCOOP, the Company has added approximately 300,000 net reservoir acres to our portfolio with the Sycamore reservoir. The Sycamore reservoir lies directly above the Woodford in ranges from approximately 100 to 500 feet thick. The aerial extent of the Sycamore reservoir is fairly well defined by existing subsurface well control. To-date we've completed two Sycamore wells and both are strong producers. The Pudge 1-7-6XH had initial flow rates of 109 barrels of oil per day and 12.2 million cubic feet of gas per day at a flowing casing pressure of 3,900 psi. Our second well the Ryan Express 1-18-19XH float at an initial rate of 225 barrels of oil per day and 7.8 million cubic feet of gas per day at 3,200 psi flowing casing pressure. Both wells have been producing for about 180 days and we currently have projected EURs for these wells in the range of 1.6 to 2 million Boe per well. Approximately 10 miles to the Southeast, a horizontal Sycamore well recently completed by another operator had initial reported by its of 860 barrels of oil per day and 16 million cubic feet of gas per day, which interestingly is very similar to the initial flowing rates were reported from our bode Meramec well in STACK. This comparison becomes even more interesting when you realize at the Sycamore and Meramec or [indiscernible] equivalent geologically. Bottom line, we're very pleased with our initial Sycamore results and plan additional wells this year to further delineate this play and perhaps some of the other merging opportunities including the Osage County and other perspective targets in the basins. Now let's move to STACK where for starters I want to point out that production grew to 29,200 Boe per day for quarter, up 20% over the fourth quarter of 2016 and up 160% over the first quarter of 2016. During the quarter, we continued our dual pronged approach to expand the productive footprint of the Meramec and begin unit development in the overpressure oil window. As we announced this quarter we had four standalone Meramec wells in the quarter and off over strong producers. In the overpressure oil window the [Swain and Mallory] were approximately one-mile wells with initial rates of 2,900 Boe per day and 2,100 Boe per day at flowing pressure of 2,850 psi and 2,900 psi and oil cuts of 74% and 51% respectively. There heard well was 10,500-foot well and flow 1,900 Boe per day at 3,900 psi and 59% was oil. In the condensate window our [indiscernible] 3,000 barrels of oil equivalent per day at an impressive 4,400 psi from 10,100-foot lateral and 10% was oil. During the quarter we also completed our second density development of the Meramec Reservoir in our Bernhardt unit in Blaine County Oklahoma. Results were in line with our expectations with a combined peak rate of 3,800 Boe per day from the five unit wells. The unit included one parent well and four new wells targeting a single layer of the Meramec Reservoir that is thin and lower quality by comparison to the other units. All well laterals in the unit were approximately one-mile and length. Approximately three miles east of the Bernhardt our first multi-zone Meramec density development and Ludwig unit continues to perform very nicely. Today the Ludwig has produced over 2 million barrels of oil equivalent from eight wells in all eight wells continue to produce in line with our 1.7 million Boe per well type curve. So I close by saying that when you're working on a petroleum system as extensive as SCOOP and STACK results generally keep getting better and you reservoirs emerge. That is definitely what we are seeing from these assets. Today we are delivering more than twice the number of barrels per dollar spent than we did just two years ago and our lease operating expenses now rank among the lowest of our peers. These value drives are direct reflection of the quality of assets and the quality of our operations company-wide. With that, I'll turn it over to John.

[John Hart:]

Thank you, Jack. Good morning, everyone. We appreciate you joining us today. Now let's first review our quarterly results was I am pleased to say all exhibit strong performance and set the stage for the remainder of the year. Revenue for the first quarter was $685 million, well net cash provided by operating activities was $470 million. Net income for the first quarter was $469,000 or nil per diluted share. Adjusted to exclude impairments, non-cash gains and losses on derivatives and gains and losses on our assets sales our income would have been $6.8 million or $0.02 per diluted share for the first quarter, EBITDAX was $483 million. First quarter production came in at approximately 214,000 Boe per day above the fourth quarter 2016 by approximately 4,000 Boe per day. We are now projecting second quarter production to range between 220,000 and 225,000 Boe per day, up from earlier projections reflecting continued outperformance in all of our plays. We will revisit annual production and exit rate guidance in August. But we now expect to be at the top end or better than our annual and exit rate production guidance. So an average of 230,000 Boe per day or more for the full-year and 260,000 Boe per day or more on the exit rate. Oil production was 56% of total production for the first quarter. As a reminder the oil percentage of total production is expected to continue increasing throughout 2017 as Bakken uncompleted wells and new Springer wells are brought online. We expect all ratios to rise to approximately 60% by year end 2017. Non-acquisition capital expenditures for the first quarter were $427 million under our internal budget by approximately $30 million. This is a part attributable to continued deficiencies in both the North and South regions. Production expense remained resilient in the first quarter with absolute cost lower in the first quarter 2017 as compared to first quarter 2016 by approximately $6 million despite increased activity and severe weather in the North early this year. On a per Boe basis it was $3.78 for the first quarter right at the midpoint for full-year 2017 guidance. First quarter cash G&A excluding equity compensation was $1.86 per Boe, slightly higher due to compensation charges and other isolated items, but it should be lower per Boe in subsequent quarters as production rises. Non-cash equity compensation was $0.59 per Boe production for total G&A of $2.45. These metrics were within or better than our annual guidance. Select cash costs, including leased operating expense, production tax, cash G&A and interest expense came in at $11.47 per Boe in the first quarter, slightly higher than the 2016 average where this production increases throughout the year these measures are expected to improve as well. Our oil differential is $7.09 per barrel around the midpoint of our guidance. We anticipate our differentials will improve through the remainder of the year once that was fully on line. The first quarter gas differential was a negative $0.29 per Mcf in line with fourth quarter 2016 and 2017 guidance. Our debt at the end of 2016 was $6.58 billion. As of March 31 total debt had decreased by $70 million improving to $6.51 billion. Our reduction in debt reflects strong production in CapEx performance. We remain committed to spending within cash flow in 2017 and are targeting lowering our debt to $6 billion or below by year end. Now I would like to make a few comments on our 2017 and multi-year outlook. As a refresher, for 2017 our capital budget of $1.95 billion is focused on spending within cash flow with our strongest production growth in the back half of the year. This production budget is cash neutral at an average WTI price of $55 for the full-year. Our move in WTI prices by $5 impacts our full-year cash flow by approximately $200 million. We have numerous areas where we can flex the budget up or down at process warrant a deviation from the current plan in order to remain cash neutral. However, we will not change the budget based on short-term price moves that we feel are non-sustainable. We will continue to monitor the relative balance of cash flows and expenditures as we progress throughout the year. Looking beyond 2017, our multi-year production growth outlook of 20% remains intact. With our current inventory, we should be able to achieve this growth and remain cash neutral at a $50 to $55 per barrel WTI. We have a lot of optionality depending on how and where we deploy capital to achieve our growth target. The main point is the depth and quality of our inventory allows for significant growth and value capture not only through 2020, but for many years thereafter. Looking further at 2018, we estimate a drilling and completion maintenance CapEx budget of $1.3 billion to $1.5 billion would maintain 2018 production at approximately 260,000 Boe per day or roughly where we are projecting to exit 2017. This would be cash neutral with WTI in the low 40's. We could achieve this maintenance level of production with no incremental rig additions and it is important to know the scenario doesn't include uplift to current EURs for additional efficiency. Therefore, we see some upside to our estimates. We will continue to provide updates to 2018 and outer years as we move forward. Let me wrap up with this. Due to strong outperformance across all of our plays, early second quarter production is running ahead of expectations for capital costs are under budget through the first quarter. Production experience is trending lower compared to first quarter 2016 despite the increased activity in early adverse weather in the Bakken. We announced strong well completions across all of our plays including record 30-day rates in the Bakken. Springer wells beating the historical type curve and strong step out wells and STACK. In summary, this sets continental up well for the remainder of 2017. With that, we're ready to begin the Q&A section of our call. Operator?

[Operator:]

[Operator Instructions] Our first question comes from the line of Brian Singer with Goldman Sachs. Your line is open.

[Brian Singer:]

Thank you. Good morning. On Sycamore, the wells that you drilled were some approximate to each other and I think a little more on the gas your side. Could you add more detail on the confidence that a) Sycamore is perspective over 300,000 acres, if it's the other industry and vertical well if you highlight on Slide 12 to get you there? And then b) what percent of the 300,000 acres would be associated with oily areas versus liquids rich gas versus dry gas?

[Jack Stark:]

Sure. Brian, this is Jack. As far as confidence in the - to say extend of the Sycamore reservoir there, there are just hundreds of penetrations out here through the formations. So geologically we have a good handle on distribution. And along the east side of our acreage block, there is just hundreds and thousands of historical vertical producers out on the east side that were oil producers in the Sycamore. And so we know that we've got production just essentially walking right up to the edge of our leasehold block, much like you see to say up in Kingfisher kind of going into Blaine County. And so we feel comfortable with the productivity in the play obviously. And what we did as we stepped out to the west and went to the west side of our acreage block because what we want to do is just do a kind of a just a bold step out here to really establish what the productivity of the Sycamore is on the further extensive of our lease block and essentially look at trying to de-risk much larger portion of our play. And so that's what we did and we drilled one well and to confirm that we actually - this was a one-off we drilled a confirmation well. So we drilled two wells there to just really prove that we could repeat that that productivity and we did. So we're very comfortable with the fact that we've got already shown that we can get repeatability. On that west side and we definitely on the east side, so quite frankly we feel really good about where the plays at right now and when you take the other industry, well I mentioned that was completed by 10 miles southeast of our wells. It starts filling in the gap. You can see that well there was 860 barrels of oil a day plus 16 million cubic feet of gas. So as far as the windows are concerned, I think the windows will probably mimic the Woodford because this sits right on top of the Woodford. The Sycamore does and so you know at this point third of our acreage in the Woodford is in the oil window or thirds in the condensate, the third in the gas. So right now I'd say that's a fair estimate of what we could expect from the Sycamore at this time.

[Brian Singer:]

That's great, really helpful. Thank you. And then on a follow-up just on the balance sheet, I think you mentioned you expect to get debt down to $6 billion of $500 million down from here. Can you just remind us whether your expectations are that you'll get there via assets sales of that magnitude after tax or via free cash flow or some other way?

[John Hart:]

We're targeting some divestitures that we're working on now. So those will certainly add to it as you noted there in the first quarter we are we obviously generated some cash flow the warning divestitures in the first quarter. But we're targeting several different divestitures of long dated inventory.

[Brian Singer:]

Thank you very much.

[John Hart:]

Thank you, Brian.

[Operator:]

Thank you. Our next question comes from the line of Subash Chandra with Guggenheim. Your line is open.

[Subash Chandra:]

Yes, hi guys. Two questions, so first on the Sycamore, I think you have a - you still might have a package for sale I guess in Northwest gradient and these well results are further south. But the map I'm not clear what variance you might be expecting and a) if you can confirm that and b) how does the Sycamore vary to Grady County?

[Harold Hamm:]

Well. As far as the geology is concerned in there, I mean we see variations in the geology, but there are just nuances to each area, but quite frankly we're seeing the Sycamore package itself is just part of this whole petroleum system and it's - as you go into this acreage is you're going from the east every block to the west you're getting substantially over-pressured. So what you're seeing here is going from really normal pressure production east of our acreage block to highly overprice as you move down into the area where the plug and run express are reported so the variation you might see is it's a transitional player we're going from oil to gas. And condensate and high-liquids obviously in between and you're also transitioning too much higher pressure regime which will improve performance in results of the wells.

[Subash Chandra:]

Okay. So the package you have out there that just so there's no geologic difference is just a time value or something like that?

[Jack Stark:]

Yes, we see these trends you know extending all the way through then. In fact we the block was put together it's a highly operated block and it was basically designed in least for that purpose for us to go in and have operations continue to develop it, but when we look at the depth in the quality of our inventory and the time that we have it just this is going to be inventory that still further out in time and resulted this is an opportunity to go ahead and look at potential monetizing that in reinvesting that down in the play to the south. I mean we don't see significant difference between it, is just it all comes down to time and money.

[Subash Chandra:]

Got it. And my follow-up is so Springer you guys had taken time off there to do a lot of work and now we're seeing the product of it and so what do you think the inventory is at that $50 cutoff?

[Jack Stark:]

Right now it really depends on what the ultimate density is going to be in there and Subash so we're still assessing that, but right now I could say that if we look at say assume you got five rigs we probably got in our dearest area right now we probably have five to 10 years inventory with five rigs depending on what the density is and we expect that derisk profile footprint to expand.

[Harold Hamm:]

And the reason Subash we held off what they need at oil prices last year [indiscernible] this is HBP acreage and so we [indiscernible] development.

[Subash Chandra:]

Right. Okay. Got it, understood. Thanks guys.

[Operator:]

Thank you. Our next question comes from the line of David Tameron with Wells Fargo. Your line is open.

[David Tameron:]

Thanks. Good morning. I want to focus on the Bakken a little bit and obviously we had some great success there. How do we think about it well I guess the first part of the question would be you talk about your proppant - like what's you do in the proppant side what you're doing that on the spacing side like what your typical completion design is and I'm trying to figure out how much more upside there it's numbers is you know are we I know you're never going to say you're fully optimized in the basin, but like how closer we are you still - are still test and more status tighter spacing et cetera.

[Gary Gould:]

This is Gary Gould. And for first quarter for 2017 it sort of 14 wells we averaged proppant loading of about 1,250 pounds for foot. And so we're encouraged by more proppant that were put in the well, but we're also encouraged by some of the work that we see done by operators where they're going to smaller stages. So in the same set of data for first quarter our average stage length was around 280-feet and we see a lot of benefit from other operators are still moving down towards 200-feet or 160-feet. And so we still see room to optimize and we plan to optimize on both those parameters moving forward.

[David Tameron:]

Okay. That's helpful. And then let me jump over to that the STACK. Can you guys I think the density test and Bernhardt despite what some of the people in the street were expecting including us but what it's sort of in line with your expectation I don't the parent well as less than the need to Ludwig parent well. But can you just talk about maybe what you see throughout playing county some of speak to some of the variability. What exactly happened this as far as just the production rates versus Ludwig?

[Gary Gould:]

From a geologic perspective as you said the parent well in the Bernhardt you know wasn't very strong well and so we didn't expect subsequent wells be that strong and really what we're seeing in this unit is the just the we're targeting the lower Meramec in this instance here in the thickness and it was a thinner zone and also just the quality of the reservoir was as good as indicated by the first Bernhardt well. So when we say the results were in line with expectations they definitely were. But so when we put in the context of what we've got out here surely we're going to have some areas in here where we don't have as good of reservoir quality development but these Bernhardt unit those wells represent less than 10% of wells we drilled so far and if you look at the whole, over 75% of wells we've drilled it to this date have over 100% rate of return. And so we're going to have a few areas out here as I told you and mention that what we have is these Meramec kind of shingle and in some areas you'll have one zone, others you have two, others you may have three and even more depending on how you divide reservoirs. But there will be some areas where they just don't quite overlap very well in between both say layers of development of the reservoir. And I think that's what the burnout is, but I think it's ultimately going to be a very small percentage because I still say that I mean these results we've seen in here been the most consistent and repeatable that I've seen in either resource place we've involved in this role in play.

[David Tameron:]

Okay. Just last follow-up, just to clarify. So you still have - I think you usually talk about six or seven units for this year, is that still the plan as far as the density test?

[Harold Hamm:]

Yes. We've got I think about two thirds of our rigs are focused on density work, the other third are looking at or doing step outs standalone test.

[David Tameron:]

Okay. I appreciate all the color. Thanks.

[Operator:]

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

[Doug Leggate:]

Thanks. Good morning, everybody. I guess my first question is going back to the Bakken if I may, can you walk us through what the balances between the dock completions and whether you are applying the same completion design to the new drilled wells. I'm just trying to get a handle, I think your docks increased in the quarter and trying to get my handle is how much of that is going to get work done over the course of this year?

[Gary Gould:]

It's Gary Gould again, and yes, we are applying the same types of optimized completion techniques to both the docks and new wells. Currently we have about 200 drilled wells that are not yet producing and we are working those down as we discussed, in a year end we expect to have 140 drilled wells that are not yet produced and that's based on our budget. And out a that 140 about half of them was already been stimulated and are ready to just very soon thereafter go on to production, so that's going to give us a great production ramp both in the second half of this year as well as into early 2018.

[Harold Hamm:]

The pads give you a little bit of a lumpiness in that and we are adding some stim crews in the summer to take advantage of the better weather, so you'll see - those will be working off.

[Doug Leggate:]

So I realized I ask this question to Jack almost every quarter, but it just seems these wells results, I mean you signal pretty well that you can revisit production or the guidance in the summer I guess, but Jack what would you need to see to reset that 980 curve on these higher completions?

[Jack Stark:]

Maybe I'd ask Gary that question because I keep asking the same thing. But now really you've got to take into consideration here Doug, these are such exceptional rates that we're seeing here that I totally understand the guys wanting to just see just how these wells - I mean right now the uplift seems strong and seems like it's being sustained. And the concern is will they fall off harder than previous curves and kind expect it will, but the fact is that - for me I really believe that we'll see an uplift in EUR here, but I'm going to be a little patience, we've always tried to be very straight with everybody and let you know exactly what we - the best we know about the play and rates and EURs and that's what we're doing here is just being a little more conservative. I think by midyear we should have a pretty good perspective. Gary?

[Gary Gould:]

Doug, this is Gary Gould. I'll add some more color to that. If you look at the curves on our slide that talks about the Bakken optimized completion. You see that some of it still going straight up and so that means there are still - the production is real flat and some of these wells have not started to decline, so makes it challenging to determine how much of an EUR uplift there is. You may recall that we have added 15% higher EUR into it based on our original budget, so that's already baked into the 980. The exciting part for us it's going to be even more than that 15% based on what was looking like. And then even more exciting on that is you look at the rate of return that we have here and even if we don't see incremental EUR, we see significantly higher rate of return like the 76% that we're seeing - that's uplifted from 40%. So whether it's acceleration or incremental EUR, rate of return is increasing either way.

[Doug Leggate:]

Gary, I wonder if I could just elaborate a little bit on that. So you gave three statistic in the release the 65% outperformance for bunch of wells, the 55% outperformance for 150 days that in the middle was to there was a 35% number. Can you spend now?

[John Hart:]

35% number, I believe - yes, I can explain that. The 35% number is the number that we reported last quarter. So if you look at the fourth quarter 16 curve, we reporter that outlasted at 90 days. I believe it was in the 90 days. It was 35% outperforming. Now were to 150 days and it's that same set of well is outperformed by 55%.

[Doug Leggate:]

For the holding out better basically?

[John Hart:]

Exactly, it was just time they're doing better.

[Doug Leggate:]

Okay. My follow-up if I may is probably for John. John obviously we're in a world that always back in the 40s, some quarters ago you talked about what your breakeven Oil price was and it looks like for the growth numbers you dropped your indication by $10 this quarter. What was driving the same topic and the same growth rate or are you understating the growth rate, in which case what is your breakeven today to let's say for that intellectually challenge of suggesting what you are what you or your maintenance capital would be?

[John Hart:]

We get a lot in there Doug. When we talked about 60 to 65 before we were speaking to what we thought our view of what's out of the price environment would be. Our breakeven at that time was - that was for the multi-year was actually below 60. I think we even say we were cash flow positive in that range. And so we're giving you a greater color to really what a breakeven on that longer term is and it's in the 50% to 55% range and it's declining throughout those years as we're bringing on production and more cash flow part of the improvement is greater clarity part of it is the improving well performance that we're seeing coupled with maintaining a strong cash flow profile, cost profile. So a lot of upside now I think there's potentially some further upside with that with these this productivity we're seeing in these wells and continuing to get better. You can see that tighten for as we go forward and so we're very pleased with that.

[Doug Leggate:]

So what is a breakeven number?

[John Hart:]

That was the maintenance capital number I gave you for 2018, if we hold flat at 260,000 a day, our projected except for this year holding flat at that requires the price in the low 40s, so 1.3 to 1.5 D and C and low forty WTI price.

[Doug Leggate:]

Harold, congrats on the 50 year a great company.

[Harold Hamm:]

Thank you. Thanks very much. First I might add to and we're saying our servers cost stabilization at first year of projection in car. Ethically we're not saying that. It's stabilizing now, a little bit creep in coupler, but overall we're seeing serves costs stabilization.

[Doug Leggate:]

That's helpful. I'll let someone else to jump on to maybe elaborate on that? Thanks Guys.

[Harold Hamm:]

Thanks Doug.

[Operator:]

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

[Neal Dingmann:]

Good morning, gentlemen. Harold, maybe just don't hear all that last comment on service costs, given what you seeing, can you talk about I guess you guys have never been able to - never really had a walk in long-term on either the drilling or completion side yet you've managed to keep your costs down. I guess is that strategy will continue the same remainder this year in 2018?

[Harold Hamm:]

Yes, I don't see as going out here and find the lot cost down. We work with vendors very well and so far we're seeing in those costs a little bit of creep, but basically its own play. Pat, you want to talk about drilling.

[Pat Bent:]

This is Pat Bent. Specifically with some drilling fee, we've had 19 rigs on long-term contract. Five of those were already rolling off and we anticipated another eight rolling off by year-end. So from the term rate, new build down to market rate in the 17, 17.5 range. So we will see some reduction in rate this year.

[Neal Dingmann:]

And what about just on the - service costs just on the sand side, I know some of these other EMPs are lock in or doing different things either with the unit train or the mine themselves and when you all talk about if you're just change your thinking as ways contracts signing?

[Harold Hamm:]

Well, there's a lot of [indiscernible] comment was the same was always been run our sand, but not out exactly. So here compound that.

[Jack Stark:]

Sure, I can recall one delay we federally or this quarter and due to weather conditions. So some of the transportation had trouble with it one due to the sand mine capacity and our crews have been working very efficiently with our service companies and during this quarter we put away as many as nine to 10 stages a day which means you've really got to be operating efficiently.

[Neal Dingmann:]

Got it. And then guys, last question last year when prices were moving around you decided to sort of build that docks inventory and change that completion cadence a bit. You mention to start of the call that you know pretty aggressively tackling these docks would if price is continue to trend like we are seeing this week today with that change would you kind of go into the mode that you did last year with you potentially increase these docks or how would you think about that?

[Harold Hamm:]

Yes, right now we that's why you get out and get all the coverage you can all over the world. We see basically us find demand balance right now what you have to have to see occur as everybody's going to toward seen this inventory the wood barrels comes down. We've seen that with floating storage come on you've got to get rid of 300 plus million barrels of the inventory and so everybody is pay clean attention to that keep it eye on it. But we believe that we will see prices strengthen as we come out of the shoulder month's refinery utilization is up. Also saying toward better prices very quickly. We'll see where that goes you know we were just accordingly with the market and you know call back pretty quickly with stem crews if we need to happen to Bakken. And so that's option you have not haven't long-term contracts and so we will keep it but we're hopeful that was better prices footprint.

[John Hart:]

Let me give you an example of flexibility Gary referenced earlier at the end of the year we'll have 72 wells that are completed but not producing. I mean the capital spent this year, but we're not getting the production at generic an example we could back off while still maintaining oil production and you know cash flow targets we can back the capital also. So there's a little a lot of optionality and flexibility and what we have going on.

[Neal Dingmann:]

Great to here. Thanks guys.

[Operator:]

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

[Brian Corales:]

Good morning, guys. Most of my questions have been ask, but just look at the spring are those wells are very, very strong. I know you increase in number completions but can we even see you know more rigs I guess maybe go from the SCOOP to or is that a target in the Woodford target the spring or based on the oil percentage.

[John Hart:]

That's what's great about our inventory here we have lots of optionality here and so right now we're working towards just building a little bit more perspective of what we can expect from the Springer both from performance and the stems longer laterals. And then also - and obviously watch price, because we consider this to be oil in the bank and we didn't want to flow it at low prices and so we made - conserve that until a better price environment once again if it gets low enough. So yes, we have the option to turn it on if we choose tube and that's the question what we choose right now. With the inventory we've got and we've looked at adding five, we still think we'll get our - say our oil percentage upwards towards 60% by year end.

[Gary Gould:]

And Brian you're exactly right these are tremendous wells from free that we're talking about here right through this call.

[Brian Corales:]

And just a follow-on to that, you're always very early about getting proper spacing with some of these density tests. Is that something you try in the Springer just to try to determine early on what that spacing is?

[Harold Hamm:]

You bet. And so that's what we're assessing, we've done some initial - if you remember we did a couple density test previously and we got two actually and we've been monitoring the results there and using those results to help us determine which direction go right now. We don't have plans to do any say density drilling right now, but you know because we're still just kind of delineating, but we do have good perspective on it right now.

[Brian Corales:]

All right. Thanks guys.

[Operator:]

Thank you. Our next question comes from the line of Derrick Whitfield with Stifel. Your line is open.

[Derrick Whitfield:]

Good afternoon all and great update.

[Harold Hamm:]

Thank you, Derrick.

[Derrick Whitfield:]

So building on Doug's previous question on the Bakken, is it fair to assume that your decline concern on the optimized completions is more B factor related than first year decline related?

[Gary Gould:]

Well I think, it's really about how much of the incremental rate is going to stay in the near-term. I mean we've got such strong pressures that these rates continue to deliver in these early months. And so when I think of B factors, I think of that B factor probably going to be the same, I don't think it's going to change because it's the same type of rock that we have. But what we're doing is we're connecting to more rock and then we're also not only optimizing the stimulation, but we're also optimizing the production lift when it comes to our overall completion. And so in earlier years - last couple years when prices were low, we didn't want to accelerate production, actually had production curtailed that we're wanting to not only optimize the completion, but also the production lift. And so that combination is what we're going to need to look at.

[Harold Hamm:]

I think there's one more factor here that we've considered as well and Gary mentioned. That is diving down the state's links from 300 foot down to about 150 to 160. We just talk - we had rock and I think that's been demonstrated here in not only production, but will be demonstrated in EUR as well.

[Derrick Whitfield:]

And that appears to be the case. Could you guys comment on your leading-edge completed well cost with the most current design in the Bakken?

[Gary Gould:]

Leading-edge completed well cost, I mean we're right on target with what we forecasted. We've been averaging around $7 million which is what our budget was based on.

[Derrick Whitfield:]

And one last if I could, so shifting gears back to the Springer. Where do you think you guys could drive completed well cost for a 9,000 for lateral and development mode?

[Harold Hamm:]

I think we're saying reductions occur here in both of those maybe another 10% that we could easily.

[John Hart:]

As far as total capital that we had in 9,000 foot lateral we'd probably be in the range of $10.5 million I would expect something around that range. Was that a question?

[Derrick Whitfield:]

That was a question, which again two - 940, $10.5 million appears to be very competitive?

[John Hart:]

Yes, yes. Certainly the longer laterals and optimize completions are helping our rate of return and certainly we've got the technology to continue to drill longer laterals. It's all about putting the land position together first.

[Harold Hamm:]

And then of the course one would get into pad drilling we'd see further downward pressure on those costs.

[Derrick Whitfield:]

Great, update. Thanks guys.

[Harold Hamm:]

Thank you.

[Operator:]

Thank you. Our next question comes from the line of Edward Westlake with Credit Suisse. Your line is open.

[Edward Westlake:]

Okay, one larger one, one smaller one. Congratulations, I mean the inventories just getting better across at last acreage position. You talked about non-core, you may not want to answer this, but it feels like the Bakken is getting better that could be some non-core disposals there. It feels like the Oklahoma businesses is very large and that could be some non-core there. But just trying to give confidence on where the balance sheet would be in two years - oil price hopefully will help as well?

[Harold Hamm:]

I think the balance sheet will be vastly better. We've indicated we would like to get down to $6 billion or lower by the end of the year. Longer-term, we would like to get down in the low $5 billion range. So in that as far as inventory, we've so packages in the Western extent of the Bakken and we've sold packages largely non-op and they're very large high quality, very desirable assets. We've got 20 to 30 years of inventory. So from a management of the balance sheet expected we have some optionality on what we do with different assets and whether we develop them or whether we monetize them earlier and reduce debt. So we clearly have the ability to do we're targeting. We've talked we've done what we've said we would do so far and we're making nice progress on the further improvements that we've discussed.

[Edward Westlake:]

And then on the Sycamore, I mean obviously we got costs for Woodford asset and this is shallow in the Woodford. So presumably should be lower cost, I mean am I thinking about that right in terms of well cost performance?

[John Hart:]

Yes, it's just a few hundred feet difference. So the cost should be right around the same as the Woodford.

[Edward Westlake:]

And then the ability to co-develop the Woodford in the Sycamore off the same path would presumably create more savings?

[Harold Hamm:]

Without a depth.

[Edward Westlake:]

So I mean I'm trying to see where you might be able to get the say a combined section development of Woodford and Sycamore?

[Harold Hamm:]

And don't forget the Springer.

[Edward Westlake:]

Yes.

[Harold Hamm:]

We have Woodford, Sycamore and Springer could be a very, very prolific unit.

[Edward Westlake:]

So any idea at this point in terms of the savings that you might be able to get from those asset - from those efficiencies?

[John Hart:]

Well, what we've seen on the pad drilling, we've seen 20% efficiency that is greater and run up to 30% efficiency on pad.

[Edward Westlake:]

Yes, and so just confirm those and also in your current numbers?

[John Hart:]

They're not.

[Edward Westlake:]

Okay. Thanks very much.

[John Hart:]

Thank you.

[Harold Hamm:]

Thank you.

[Operator:]

Thank you. And I'm showing no further questions at this time. I'd like to turn the call back to Warren Henry for closing remarks.

[Warren Henry:]

Thank you. Thanks again everyone for joining us this morning for our call. As you can tell we're very excited about our assets and the execution in all of our plays. So we look forward to reporting another very strong quarter to you in August. Have a great day. Thank you.

[Operator:]

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