Continental Resources, Inc.
Q2 2017 Earnings Call Transcript

Published: 10 Aug 2017

[Operator:]

Good day, ladies and gentlemen, and welcome to the Continental Resources Second 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. Sir, you may begin.

[Warren Henry:]

Thank you, Kelly and good morning to everyone joining us today. We will start 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 of Exploration; Pat Bent, Senior VP of Drilling; Gary Gould, SVP Production and Resource Development; Steve Owen, SVP Land; and Ramiro Rangel, Senior Vice President, Marketing. 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 on the call, we will refer to initial production levels or IPs for new wells, which in most cases are maximum 24-hour initial test rates. The well economics, to which Jack will be referring in his remarks are based on $50 WTI and $3.25 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. With that, I will turn the call over to Mr. Hamm. Harold?

[Harold Hamm:]

Thanks, Warren, good morning, everyone. I realize it's been so many of you long arduous reporting session and I'm glad we have a quality report for you this morning. Continental second quarter 2017 was the definition of solid focused execution with growing production growth, improved operating cost and disciplined capital spending. Continental delivered more production per dollar invested demonstrating both, improved capital efficiency and increased productive capacity. Consequently, we have elevated our 2017 production growth guidance raising the expected range for exit rate to 24% to 31% above fourth quarter 2016 production. And even more significant we expect to accomplish this within the same capital expenditure budget or less as well as adjust to commodity prices to be cash neutral. Our outlook in corporate further operating efficiency such as reduced drilling times and lower costs of operations and transportation for daily production. As we said yesterday, we expect to see oil increase as a percent of our production through the back half of 2017 and into coming years as a continued focus in the Bakken and then the springer formations. Our improved guidance outlook reflects an even broader aspect of Continental story. Now during the past three years of cross volatility, Continental has reset it's priorities and recalibrated its growth strategy to pluck the new era of U.S. energy technology. Having ownership of Tier-1 quality rock assets and multi-decades of highest quality drilling inventory, we're now capable of growing production at the industry leading and much lower level of capital investment compared with any time in our 50-year history. Since 2014 we've been -- we have more than doubled the reserves found for capital dollars spent. This evolution is especially timely given the historic adjustments in oil markets as America re-emerges as the dominant world energy leader. Today the future clearly lies in the hands of those few top U.S. energy companies that own the best quality assets and have the lowest cost operations; Continental is the leader in both these categories. In addition, our company record as a leading exploration is still unmatched providing decades of premier inventory of Tier-1 quality rock. Well results within our portfolio continue to improve with optimized completion and as a mature hands-on driller we continue to innovate new methods of delivering the best operating efficiencies to execute a growth strategy with precision and discipline and reference to market conditions. Our optimism is further supported by changes in the industry, especially the heightened emphasis on CapEx discipline. As multiple companies have noted, EMPs are tapping the brakes on drilling and making more rational capital decisions in the face of oil prices and the best interests of the shareholders. For our part we have never supported a position of perpetuating a market oversupply by selling our inventory at unsustainably low prices. Continental has forgone hundreds of well completions in the Bakken and 80% oil plus oil resource and even postponed the drilling of it's spring [ph] old field which is also an 80% plus resource during this period of market readjustment. Jack will provide color on two recent completion test in the springer showcasing what a great asset we have in the springer. Stay tuned in the coming quarters as we provide development plans for this asset in a rebalanced market. In the face of low oil prices we have recently released three grown rigs and four completion crews. This is 20% reduction in rigs and cruise while increasing our production outlook, this speaks directly to our operational efficiency at Continental as well as the disciplined business approach we're taking here. Continental remains bullish and focused on oil, the market is in the process of correcting as is the disparity between WTI and Brent. The new light oil refining capacity comes online and increased export shipment of light crude take place, this differential will be eradicated to return to dort norms of WTI dominance over Brent. But in the meantime we believe that the long-term world supply cannot be sustained at $50 WTI. There simply won't be adequate capital, investment long-term at this price to adequately supply market demand growth. We are now saying EI to take corrective measures to more align their model with the actual production data and we commend them. Our other priority at Continental includes further debt reduction to reach our internal target of $5 billion to be realized over the next few years. John will provide details this morning on additional recently signed PSAs totaling $148 million in expected proceeds. Although natural gas production is not our primary focus here it does contribute meaningfully to our cash flow and our gas assets provide attractive rates of return. We see opportunities for enhanced economic to the go -- over market for LNG. The IEA, the International Energy Agency, post this gas 2017 report last month forecasting strong LNG demand growth through 2022 and projected that U.S. will be one of the three largest LNG exporters by 2022. Companies are already participating in this market through a joint venture agreeing with SK E&S in South Korea. Since 2014 we've been producing natural gas in Central Oklahoma for domestic purposes and Bent [ph] for South Korea. It's been an outstanding success for both companies providing SK with predictable long-term supply and delivering excellent return for Continental. Reasonably we were among several companies that signed a Memorandum of Understanding with SK to explore additional areas of cooperation in the U.S. Continental is also actively pursuing additional joint venture opportunities which could be significant for us. The proximity of our SCOOP and STACK assets to the Gulf Coast positions us well to expand our participation in this growing LNG market. Thank you again for your support, and with that, I'll turn the call over to Jack.

[Jack Stark:]

Thank you, Harold, and good morning everyone. Thanks for joining us here today. As Harold pointed out, Continental delivered another strong quarter of disciplined growth with the results exceeding even our own expectations, we now expect to exit 2017 with production rates 5% above our original 2017 guidance based on the midpoint of the range. True to our commitment, we plan to deliver this accelerated production growth on a cash neutral basis. At WTI prices ranging from $45 to $51 per barrel and $3.25 Nymex [ph] gas. It's also important to note that this outperformance is being achieved with greater capital efficiency and longer operating costs than originally guided. Our updated 2017 guidance provides strong reinforcement that Continental is and will continue to be one of the lowest cost operators in the industry delivering some of the best margins and recycle ratios among our peers; and yet the best is yet to come. Our outstanding performance are driven by four key factors; first is the superior quality of our assets. It all starts with the rocks; our Bakken STACK and SCOOP assets are locating some of the most attractive geologic portions in these plays and deliver some of the best economics in the industry. Our 2017 drilling program is targeting rates of return ranging from 70% to over 100% from these assets. Looking ahead we have decades of high quality oil weighted inventory secured for double-digit growth with approximately 70% of our $2 million net reservoir acres now held by production. This provides us critical optionality and flexibility to adjust our business plans and commodity mix to best capitalize on the market conditions. The second key factors are optimized completions which are improving performance in all of our assets. In the Bakken, our optimized completions are bringing on company record wells over a broad cross-section of a play. Rates of return for typical Bakken wells have been doubled to 82% generating over $2 million of added revenue during the first six months. We also increased the type curves for Bakken wells by 12% to 1.1 million Boe for 9,800 foot lateral well. In the SCOOP Springer our first optimized one mile well reported last quarter has produced almost twice as much oil during its first 90 days than our historical 940 MBoe equivalent type curve. The cash 126H flowed more than 1,200 Boe per day on average during its first 90 days with 82% of the production being oil. The cash flow is projected to pay out in 12 months delivering more than 100% rate of return. Based on these results we believe the Springer may ultimately deliver some of the best, if not the best economics in the country. The third factors are improving crude oil differentials. Our crude oil differential guidance for 2017 has improved by $1 to a projected range of $5.50 to $6.50 per barrel for the year. In the Bakken our crude differentials have already strengthened as much as $2.40 in the local markets. Overall, we expect our Bakken crude differentials could improve by as much as $2 per barrel on average in the second half of 2017. We also expect to see continued downward pressure on crude differentials and SCOOP as additional infrastructures developed. And finally, the fourth key factor and continued -- are the continued official gains being generated by our operating teams. In the second quarter we saw the compounding effect of added drilling efficiencies and lower day rates as rigs came off term contract. By year end, 10 of the 18 rigs will have come-off contract in 2017 saving approximately $10,000 per day per rig. A good example of our ongoing drilling efficiency gains come from the 10-well comp and density project in STACK where drill times for the Meramec density wells were decreased by 50% from the parent well. This reduced drilling costs approximately 35% saving approximately $2 million per well for a total of $18 million for the project, this shows the significant cost savings that lies ahead as we move into full development. Another great example of efficiency gains comes from the Bakken where drilling teams have achieved yet another milestone. For the first time they did not have a single lateral sidetrack during the quarter, this means every well was drilled entirely within a targeted reservoir. This is especially impressive considering they were drilled -- they drilled 25 wells with a total of 49 miles of lateral well bore. During the quarter the Bakken team also said company records achieving a remarkable 6,000 feet per day in the vertical portion and 6,293 feet per day in the horizontal portion of two separate wells. These achievements come from the dedication and ingenuity of our employees and I can tell you; you can depend on them to continue to set the bar high when it comes to performance; operational excellence with superior assets, that's Continental. Now let's take a look at a few other results for the quarter. In the Bakken we completed 19 wells with an average initial rate of 1,600 Boe per day with 82% being oil. Five of these wells ranked among the Top 10 Bakken producers for the company based on their first 30 days of production. In addition, the Cooper [ph] wells in Dunn County were excellent producers and expanded the successful footprint of our optimized completions 40 miles south of our activity in Northeast McKenzie County. In STACK we continue to derisk the Meramec reservoir completing six standalone wells during the quarter. These wells had average initial rates of 1,915 Boe per day with average oil cuts of 45% and average lateral length of 6,870 feet. We recently completed another stepout well, that is a record setting well for the Meramec and STACK. TRES C FIU 1-35-2XH float at the remarkable rate of 1,021 barrels of oil and 29.6 million cubic feet of gas per day or 5,953 Boe per day. This was a 9,750 foot lateral and it produced this rate at an impressive 6,500 PSI full income casing pressure. Adding in the additional 1,978 barrels of anticipated natural gas liquids post-processing, we estimate 24 hour rate for the TRES C would be 7,442 Boe per day with 40% of the production being liquids on [indiscernible] basis. Now I have to say, this is the strongest flowing well I've ever been associated with in my career. Now for perspective, the company has announced the completion of 48 overpressured stacked Meramec well to-date. Results of extended the productive footprint of the Meramec, approximately 25 mile south and 35 miles west from Eastern Blink County into Dunn and Costa [ph] counties. The wells have established production from three Meramec reservoirs including the upper, middle and lower reservoirs as we have them defined today. Approximately one-third of the wells have been completed in each of the three reservoirs. The initial range of 24 hour IPs from these wells and each are really quite -- and each of these reservoirs is quite similar and the average initial rate for wells in each reservoir falls within 20% to 25% of each other. So these are very good statistics given the overpressure STACK is so early in its development. These results are also in line with our geologic model. In addition to our stepout drilling, we also have seven Meramec density tests underway in STACK to determine the well density needed to maximize recoveries and the net present value of each unit, and increase -- basically try to improve that in each of these. We have over 265 operated units for potential development underlying our 207,000 acres on STACK. The first two density tests we completed were in the Ludwig and Bernhardt units. We are monitoring the production from these units closely and are pleased to see that the density wells continue to produce in line with apparent wells. To illustrate, our production chart of the Ludwig unit wells is included in our slide deck on Page 22. The Ludwig unit density wells have been producing for about 300 days. We recently began flowing back our third Meramec density test in the Blurton unit. Blurton was an eight well density test with three new wells in the upper Meramec, four new wells and one parent well in the lower Meramec. Lateral links averaged approximately 10,000 feet. The unit is in the early stages of flowback and has not reached peak production rates. To date, the combined 24 hour initial rate we have recorded from the eight wells is 10,514 Boe per day with 78% of the production being oil, including anticipated post-processing natural gas liquids to combined estimated initial 24-hour rig would have been approximately 11,883 Boe per day on a three stream basis. The wells continue to clean up, and as they do oil production is aligning with the parent well. At day 22, the seven density wells are producing at average rates that are approximately 80% of the parent well. We continue to monitor the performance of these wells and will incorporate the results with other ongoing density tests to design our future develop plans for the Meramec reservoirs. This quarter we also introduced our type curve for the STACK Meramec condensate wells with a projected EUR of 2.4 million Boe for a 9,800 well. This type of curve delivers an 80% rate of return assuming a complete well cost of $10 million. In SCOOP we completed another excellent Springer well, the Robinson well completed flowing 1,636 Boe per day from a 7,700 foot lateral with 82% of the production being oil. This was a strategic well designed to drill and complete a thinner portion of the Springer where the reservoir gets down to approximately 20 feet thick. During the first 60 days the Robinson has produced at an average rate of 1,350 Boe per day and has produced historic -- our historical 940 MBoe type curve by 89%. One last thing before I pass it on to John; during the quarter we also completed two Woodford wells in the Cottonwood project in Stevens County, approximately 10 miles south of our -- most of our SCOOP Woodford activity. These were optimized completions in an area we had not completed wells for a couple years. The wells had an average initial rates of approximately 2,100 Boe per day with 26% of the production being oil. Once again, both wells are outperforming legacy wells in the area by 80% to 90% during the first 30 days. With that I'll turn the call over to John.

[John Hart:]

Thank you, Jack. Good morning, everyone. We appreciate you joining us today. I'll start with a quick review of our second quarter results and then get into the updated 2017 guidance and provide an early outlook for 2018. Revenue for the second quarter was $661.5 million, and net cash provided by operating activities was $446.4 million. Net loss for the second quarter was $63.6 million or $0.17 per diluted share. Adjusted to exclude impairments, non-cash gains and losses on derivatives, and gains and losses on our assets sales our loss would have been $1.8 million or NIL per diluted share for the second quarter, EBITDAX was $479.5 million for the quarter. Second quarter production came in at 226,213 Boe per day, above the high end of our quarterly guidance and above Bloomberg consensus estimates. We recently reached the milestone in early August with production reaching 250,000 per day over several days. We are projecting third quarter production to be in a range of 240,000 to 250,000 Boe per day reflecting timing of completions. Oil production was 55% of total production for the second quarter. Let me provide some color. In the first quarter oil was 55.8% and in this quarter it was 55.4%, so essentially flat quarter-to-quarter, just a slight rounding difference. This oil production percentage was inclusive of working interest adjustments in the second quarter, otherwise the oil percentage for the quarter would have been above 56%. As a reminder, the oil percentage of total production is expected to continue increasing through the back half for the year as Bakken uncompleted wells and new Springer wells are brought online. We expect the oil percentage to rise in the third quarter to around 58%. We feel comfortable with this investment because we're already there. We've averaged 58% for the last 30 days. Recall that at the beginning of the year we got it that our growth would be back half weighted due to our Bakken Ducks being on large pads. This provide some lumpiness but as you can see by our exit rate for the year, a lot of growth is coming. We expect the oil percentage to continue growing through the balance of the year and in 2018 as more Bakken Ducks come online. We are targeting 60% by year end and 60% to 65% oil over the next few years. Non-acquisition capital expenditures for the second quarter were $551.9 million as we took advantage of summer weather to increase completion activity in North Dakota. At times we operated eight completion crews in the Bakken. This level of activity was planned and we have since reduced to four Bakken crews reflecting capital spending adjustments to align with lower commodity prices. Production expense increased slightly in the second quarter to $3.99 per Boe, this is not indicative of a trend and we expect the full year to range between $3.50 and $3.90 reflecting an improvement of $0.10 in the top end guidance. The second quarter increase was attributable to a higher level of expense workover. As has historically been the case we took advantage of warmer weather to address workover activities, particularly in North Dakota. Expense workover installed [ph] at $14.9 million in the second quarter, as a reference point we averaged 8.5 million per quarter in 2016. We expect a lower level of expense workover activity for the balance of the year. Second quarter cash G&A excluding equity compensation was a robust $1.45 per Boe. Non-cash equity compensation was $0.44 for Boe for a total G&A of $1.89 per Boe, below the low end of our original 2017 guidance. We have improved our guidance downward to reflect continued operating efficiencies. Select cash cost including lease operating expense, production tax, cash G&A and interest expense came in at $10.99 per Boe for the second quarter, lower than the first quarter and this should continue to improve as production ticks up in the second half of the year. Oil differentials were also lower in the quarter as Jack noted and we expect them to continue improving. Last night we announced the best interest totaling approximately $148 million, these transactions are expected to close during the third quarter and the associated proceeds will be applied to debt reduction. We continue to work on several other divestitures and potential joint ventures supporting further debt reduction. Our near term goal is to reduce total debt to $6 billion or lower, and then to reduce debt further to $5 billion within the next few years. We're seeing a lot of market interest and we are making good progress in our marketing efforts. Now I'd like to discuss our improved 2017 guidance. Let's start by reviewing capital expenditures; obviously we are witnessing volatile oil prices, so let's review some ranges. We currently expect expenditures for the year to range between $1.75 billion and $1.95 billion; the full year cash neutrality process on the stated capital expenditure budget of $1.95 billion has improved to approximately $51 WTI, $4 below our prior guidance of $55 reflecting well outperformance and cost improvements. We are currently forecasting capital expenditures below $1.9 billion, should we continue to reduce spending the cash neutrality WTI propose that $1.75 billion would be approximately $45 for the back half of the year. Key points to all of this; we intend to be cash neutral and we delivered the following updated guidance which reflects better results. We increased our exit rate production guidance to a range of 200,000 to 275,000 Boe per day reflecting strong results across the board from optimized completions and efficiencies. Note, we are delivering this production uplift within the confines of our existing CapEx budget or lower. We expect full year production to now be between 230,000 and 240,000 Boe per day compared to the previous range of 220,000 to 230,000 Boe per day representing approximately 4% improvement at the midpoint. Next, we've improved our guidance range for all differentials by $1 to a range of $5.50 to $6.50 per barrel and adjusted gas differentials a bit wider to account for lower liquids for us. The gas differential is now a negative $0.10 to negative $0.50, once oil processes improve we expect our NGL prices will improve benefiting the gas differential. Cash G&A has been reduced to a range of $1.35 to $1.75 from the previous range of $1.50 to $2 per Boe. Finally, we're lowering our DD&A guidance to a range of $18 to $20 per Boe reflecting continued capital efficiency improvement. In summary, the company continues to focus on generating capital efficient returns, rest assured we are not done. We previously provided multi-year views of cash neutral 20% growth in a $50 to $55 environment, we also indicated maintenance capital $1.3 billion to $1.5 billion as cast neutral in the mid-40s and it would support us holding production flat at 260,000 per day in 2018. These remain good estimates but can likely be improved as we move forward. Let me provide an additional scenario with our current exit rate target of 260,000 to 275,000. We estimate in 2018 the drilling and completion CapEx of $1.4 billion to $1.6 billion would hold us flat in excess of 270,000 Boe per day. This represents an annualized growth for 2018 of approximately 15% versus the midpoint of 2017 guidance and is cash neutral in the low to mid 40s. Rigging completion crude counts in this scenario would be flat with 2017 averages as 2018 would also benefit as we work up Bakken Ducks. Our plans for 2018 are being developed and these reference points are only sensitivities to demonstrate that we are well positioned for 2018 and expect to deliver strong results, not only next year but also in latter years. Our focus will be to generate strong returns on invested capital on a cash neutral basis. With that we're ready to begin the Q&A. And I'll turn it over to the operator. Thank you.

[Operator:]

[Operator Instructions] Our first question comes from the line of Doug Leggate with Bank of America. Your line is open.

[Doug Leggate:]

Thanks and good morning everybody. I've got a couple of questions on some of the new guidance items if I may. So, I'm not sure if you want to take this one but specific to the 20% growth target, can you tell us what the equivalent oil growth target is because obviously the oil yield is going up but it looks to me like the oil growth is going to be a little better than that. So can you give us some color there please?

[John Hart:]

Yes, I mean the 20% we're talking about is sort of Boe but the oil percentage is going up faster than that to get us into that 60%, 65% range. I don't remember the exact changes in the oil percentage but as we look through the balance of '17 as an example, obviously for us growing to 58% in the third quarter where we're at today and then continuing to increase in the fourth quarter, you're seeing double-digit growth in your oil percentage compared to the second quarter through the third and the fourth quarter of the year, it's kind of the quarter-over-quarter. Hence it will continue into the outer years as we raise that up and with the high level of ducks that will have at the end of '17 in the Bakken, that's giving you strong oil focused growth that can be brought on rather quickly.

[Doug Leggate:]

I appreciate that John. My follow-up is in the Bakken, if you don't mind, the expansion done into Dunn County can you talk about what -- so you haven't given us an infantry update and I guess in quite a while; can you talk about what's happened to what you think is your economic inventory and what proportion of thought would qualify as the 1.1 million tight curve? And I'll leave and let someone else jump on after that.

[Jack Stark:]

Doug, this is Jack and maybe Gary want to add something here but you know, I -- look at this, it's -- what we're saying these optimized completions are basically uplifting the performance of wells over a broad cross-section of play as we said. And so as a result we see the inventory actually -- the economic inventories, you want to call it growing and trying to put our arms around what that is today is probably a little bit premature; I mean as we've said, we've got a couple decades of inventory, I heard and definitely over 10 years of really the high quality inventory and so I just don't -- I think we're going to see that footprint, we are seeing it expand as a result of this work; so stay tuned is what I'd say.

[Harold Hamm:]

And you might give inventory on the Ducks, we're not reducing the fastest fleet. I wanted to because of the efficiency of growing up there.

[Gary Gould:]

Right. So I think some of the great news that we've seen this quarter is that we're increasing our production guidance while reducing our range of CapEx. And at the same time we're going to have a higher duck inventory that what we planned on with the original budget, an extra 20 ducks. And so what you're seeing is higher production per well as you're also seeing from our type curve. And I think one of the great things about this increase and EUR -- it's just not EUR increasing, but the rate of return doubling, the PV10 [ph] going up by 70% and the payout being slashed by 50%. And so all those things are happening early on in the life of a well; and when you look at rate of return, PV10 payout, those things are going to be captured very early in the life of these wells, first couple of years as we develop it.

[Harold Hamm:]

Yes, that's a great point Gary because -- I mean, really to these optimized completions, what we're seeing is not only uplift at EUR but we are -- we're basically uplifting the value of the Bakken assets across the board.

[Doug Leggate:]

I appreciate the full answers guys, you guys have made great progress. Thanks so much.

[Operator:]

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

[Brian Corales:]

Good morning and great update. I'll start with the Bakken as well, I mean it seems like you were clearly seeing the uplift in the enhanced completions, are you all done kind of tweaking and found the recipe or what other things you are -- or you are still try to experiment?

[Harold Hamm:]

And so you've seen our results from 2017 and if we look at the wells that we've put on first production, that average characteristics for the completions are still at 40 stages and above 1,250 pounds of sand per foot of lateral. And one of the things we've been testing more recently but we don't have a lot of wells on yet is even tighter stage spacing where we made tests -- we are testing 60 stages for two miles instead of 40; and so that's a big additional upside for us. In addition to that on the production side, we're continuing to test a higher capacity, artificial lift and we're also looking at more ways that we can get more aggressive with our facility designs also; so we're working on both, the completion and the production side.

[Brian Corales:]

Thank you. And then -- and maybe to John's comments, I mean you've done a great job spinning within cash flow, still having fantastic growth. Is that how we should think of Continental going forward as cash flows or your proxy for spending; what could we could potentially see -- a potential dividend down the road or share buybacks or something of that nature; how should we think about it going forward couple years?

[Harold Hamm:]

Well, one thing we have targeted Brian of course is debt reductions that $5 billion number, we won't say that burst before we look at many of those as things as I just mentioned but absolutely spend within cash flow, it's very important to us and -- so we're doing and actually I have postponed some development and some very lucrative fee also like Springer. And that were testing some things there as well as we did with this Roberson Well and also with the Density down there. So we're going to be ready to go when market turns but you know, absolutely no new depth. That's part of a plan, a strategic plan going forward and doctor debt down and then go from there. Brian and run a remarkable thing is we're still delivering strong results that we are even with our moderation and as we projected out into the future, I mean long ways we looked at our 5 to 10-year expectations with the quality of assets we've got and with the strong execution of our teams, we are going to deliver exceptionally strong results across the board and we can do that in a cash neutral environment.

[Brian Corales:]

Thanks guys, I appreciate it.

[Operator:]

Our next question comes from the line of Jew [ph] with Morgan Stanley. Your line is open.

[Unidentified Analyst:]

So we've talked about the capital allocation, at least you're thinking about at high level in 2018, how does the Bakken compete for capital with -- there is really nice improvement in results we've seen recently; so possibly actually add rigs there; and you -- I think Harold in your prepared remarks talked about additional Springer activity and just talk about what you're thinking in a high level right now for Springer next year?

[Harold Hamm:]

The good thing about the Bakken is, we have a lot of wells that -- we all have to just complete them. So we can bring a lot of production from there very economically; so that's always going to be kind of at top of the list without adding rigs, that's a good thing about the Bakken. So based on -- there but we're probably looking at about 50-50. As far as the Bakken compared to what we have here in STACK and SCOOP, and so that's going to be about the mix going forward.

[Jack Stark:]

And regarding the Springer, right now we're essentially seeing a playup -- but with the Springer we're just in the process of sentilating [ph] that play up and having it ready to go is what price is firm and right now we have a density project going on down there which is called the Celeste and we've got three rigs drilling in it right now; and we're going to -- it's a six well test where we're going to be able to just see one more piece of evidence of what we're going to need to understand what it feels about them to look like in the Springer. So we're doing that and so we're making plans and the teams have their perspectives on how it would go about developing it but again, we're just waiting for prices to firm and so we can sell this oil into a better price environment.

[Gary Gould:]

This is Gary Gould. I was going to add one more thing, I mean you see this quarter where we've reported out a new much higher rate of return for the Bakken, and then we've also shown you the higher rate of returns that we're seeing from our four new wells; so what we've done now is just a very strong rate of return, oil inventory that matches up very well with our strong rate of return; condensate inventory. And so we've got great flexibility to grow this company while remaining oil weighted.

[Harold Hamm:]

We're in a good position, we've got a lot of optionality. We -- all of our assets are good, the Springer, the SCOOP in general and the various zones and that, the STACK, the Bakken, we've got high rates of return across the board, so we've got a lot of optionality and consistently a good position, not only for '18 but for a decade in front of us.

[Unidentified Analyst:]

The company has a really strong outlook. So just one follow-up there waiting for firming of prices; did we have a specific number in mind of what oil price you would want before you accelerate the Springer program?

[Harold Hamm:]

Well, we see a couple of things, we see a positive trend setting up right now with pricing. Obviously, we're getting closer to market balance, supply and demand, we've seen negative reporting from our peers of about 4% on CapEx and production this quarter. Galaxy [ph] included the whole universe is still a negative, so we believe that's -- that part of situations is setting up and like we've said, we also see some positive things occurring, again with the dollar. The strength is dollars can't hurt us in real terms, here we only get parole; as that goes the other direction, that should materialize and a stronger WTI first. So we're seeing some of these things occur, we'll get into the mid-50 range; yes, I think that would encourage us to realize it. And then, we need to see market balance happening. Then you can kind of predict ahead, don't worry of where it's going. Once that occurs, and see that stabilizing and becoming a reality, then you could beat the market.

[Unidentified Analyst:]

Thanks, Harold. This is a great update.

[Operator:]

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

[Brian Singer:]

Good morning. You talked about 20% degradation in early production rate from the density wells that Blurton versus the parent well; what level of degradation in density wells do you expect in your base case? And separately, can you refresh on your spacing assumptions around the STACK condensate area?

[Jack Stark:]

Well, at this time we're monitoring this production to really understand what if any degradation is happening in here, you know, to these wells and what we're seeing is -- and we put that type curve or basically that curve in there; I think it's Page 22 for the Ludwig, so you could see -- you could see all those wells, the density wells are performing relative to the parent and are really tracking on top of each other very nicely. So it's intuitive that you would some degradation, it depends on the density of spacing of the wells that's put in here as that how much degradation you may see; so that's the purpose of us going out here and drilling four well, five well, and even a six well density set of pilots out here to really get an understanding of that Brian. So it's good questions and there is a point of diminishing returns but one of the key things here too and Gary had mention that kind of earlier was that, what we're really looking for here is to try to basically find what is the right number of wells to generate the maximum net present value for a unit; so even if you have some degradation the net present value of that unit could be significantly higher with maybe 25% degradation in the EUR but the net present value is much higher and obviously that's going to depend on oil price and what have you but the bottom-line is that; that is ultimately where these players are going to go, watching the parent well, the children well is important early on but ultimately what we're looking for is, what is the right number of wells for them to maximize the net present value of those units. So you should -- it's just -- you're -- to get the maximum net present value just makes sense that you're going to see some degradation, just how much is what we see, I have to see what we can tolerate.

[Brian Singer:]

Got it, thanks. And then shifting to the inventory, both in STACK and in Bakken. In STACK condensate, can you add some color on how prolific EU think EBIT [ph], this new tight curve applies across the acreage that's outside your 47,000 acre oil window when I think Slide 15. And then in the Bakken, maybe to ask Doug's earlier question slightly differently; if you are to maintain the rate of completions you're doing this year and future years, how many years of 1.1 million Boe wells which you have until you have to move into an non-core.

[Jack Stark:]

As far as the condensate windows concerned, right now let's say probably about 25% of our acreage is in that condensate window in STACK as it stands right now, I mean the best we got -- remember we're still pushing this play from just out into the West and so that will become more well defined but that's what we see right now and probably around one-third of our acreage is in the overpressured oil window and the rest is in the natural gas. And as far as performance is concerned, I mean we expect to see -- I mean this is an 8-well average that we've got in here right now, so we're trying to give you some indication of where we think these condensate wells, how they will perform but 8-well is a pretty small sampling and while we have to get more wells in there to really firm that up but to me it's -- right now that's what that will support, you can see the charts in our book here and it just looks really strong. So, then our TRES C well, you look at it and I mean, my gosh, that thing -- there is a record producer producing 7,400 barrels of oil or total liquids Barrel of oil equivalent there and I'm sitting here going -- this is -- and this thing is flowing at 6,500 pounds. I mean this is just an amazing well and it's not the first one, I mean there is other wells, I mean we've seen other wells with really strong pulling pressures throughout this play and so what we're doing is we're derisking the play by zone as we [indiscernible] and right now we've got three zones that we're looking at and there are areas that one zone where one zone is best developed [ph], where the other zone is best developed, they are staggered and they kind of shingles on top of each other, at some places they are really stacked on each other. So bottom line is that we expect to see these kind of results elsewhere in the play, we're not done.

[Harold Hamm:]

I hope I didn't over invited here, that's the largest well so far grilled and record that we know in STACK buy.

[Brian Singer:]

Got it, thanks. And in the Bakken years of 1.1 million yield [ph].

[Harold Hamm:]

I think -- yes, and it's early to be able to exactly address that but what we just did was we uplifted the whole area. So -- and not only just in the EUR but even more so in magnitude, in terms of PV and rate of return, and so it just speaks well for the entire basin. Brian, we can get back to you with that number, just offhand we're -- I'm think it's probably 10 years’ inventory but we'll quantify that for you.

[Brian Singer:]

Thank you very much.

[Operator:]

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

[Robert Morris:]

Thank you. Jack you mentioned that you are pursuing additional joint venture opportunities; would those be within the core areas in SCOOP, STACK and Bakken or would they be what you now consider non-core areas and I know it's been a few years but it's you're like -- you're out of line over 500,000 acres in which you're pursuing then seven different stealth [ph] projects. Are the CVs targeting non-core assets or things outside of your core areas or would they be within the core areas, maybe with the emerging Springer or something you know.

[Jack Stark:]

Well, it's actually a mixed bag of opportunities that we would be looking at; either a divestiture, if it's a non-core asset or perhaps a joint venture partner, if it's a very attractive asset that we'd just like to accelerate the value for it. So to me, we've been blessed overtime to build just as amazing portfolio of assets that are delivering such great returns that we are now optimizing our inventory and optimizing our footprint in these plays to put the company and shareholders advantage; so it's a great position to be in.

[Robert Morris:]

So it could be something to accelerate, you know if you're already activating some of that going forward?

[Jack Stark:]

Without a doubt, I mean you look at our SK DD&A [ph], I mean that was a great example of taking basically an asset and bringing that value for through a joint venture partnership.

[Robert Morris:]

Yes, I agree. Thank you.

[Operator:]

Our next question comes from the line of Iran [ph] with JP Morgan. Your line is open.

[Unidentified Analyst:]

Good afternoon. I wanted to ask you quickly on the CapEx reduction in 2017; if you could maybe just detail -- I think you're cutting the rig count by three where the rig count cuts our in terms of play and secondarily, how much of the sac that I think you stimulated well, so plan to have in the Bakken or with 70%, previously going onto $35; how does that influence the CapEx reduction?

[Jack Stark:]

Completions activities are obviously; I mean going from picking out around eight crews coming back down to four that's a big delta. As I noted on the call, we're currently forecasting below 1.9; depending on commodity prices we may flex that down or up as the case maybe, that's a mixture of rig activity and completion crews. If we were to trend down towards the low end of the range that would back-off more completion activity in our various plays and also have a little bit of rig activity, but probably largely on the stem side. But like we said on the call, we're going to hit our guidance either way and we feel good about this year and we feel extremely good about '18 and the years beyond that and what we can do. Pat, do you want anything on the rigs that we've reduced?

[Pat Bent:]

Yes, on the three rigs that we've reduced; our Bakkens remain at four, Jack has indicated earlier, well that's 2017 with 18 rigs, the three were in Oklahoma, two in our overall STACK play and one in SCOOP.

[Harold Hamm:]

We've got a lot of flexibility right now but a little bit less than half of our rigs are on longer contracts, so we've got a lot of flexibility there and stems. And the other key thing is our acreage position across the entirety of the company it's an excess of 70% HBP. So we're in good shape.

[Unidentified Analyst:]

Great. And my follow-up is just -- I was trying to do the math around the Blurton pilot; you guys mentioned that the children wells were performing at 80% of the rate of the parent, so I know that the Blurton IP did like 2,300 Boe so the implied math for the other seven would have been around 1,200. So I'm just wondering if you can give us a shape of how -- as you think about the production, just trying to think about in my head how the how has been to get to that 80% of the parent. The question makes sense?

[Gary Gould:]

Yes, sure. This is Gary Gould and I think you have mentioned that correctly, as far as the average is around 1,200; so the parent was dropping off to around 1,500 which gives you that 80% and what we really like as far as what we're seeing is the continued strong fluid production that we're seeing which shows really good rock permeability and a good completion. And then secondly, the increase in oil cuts that we're seeing from these children wells and so the trends are going in the right direction there.

[Harold Hamm:]

And I think the longer production profile, I mean these are still very and hyped; so compared to where they are at near production profile with pre-sale [indiscernible].

[Jack Stark:]

Keep in mind there is a lot of fluid that is pumped in when we're stimulating all these wells and these units; so these children well have to have -- also have to kind of start getting that fluid out in the water, the FRAC fuild is out of the reservoir, so the hydrocarbons can start coming in. And so what we're seeing here is just a continued increase, and total fluid is equal or greater than the parent well and the oil costs are climbing as the water cuts come down. And so what we're seeing here is just these Blurton unit for instance, we're just saying that the wells needed a little time to clean up and so the hydro-cards [ph], it's actually a break-through and we can see truly how these well-formed. So we're 22 days into it and so we've put that out there to just give you a perspective on where these wells are at and there is still climbing in their oil cuts and their rigs. And that's why this production profile are so important here, I mean want one a density test, you're loading the entire with fluid where a single parent, well you're not, you just have that well that you're charged.

[Unidentified Analyst:]

Great, thanks a lot.

[Operator:]

Our next comes from the line of Brad [ph] with RBC. Your line is open.

[Unidentified Analyst:]

Good morning everyone. Just like at the five, you guys are still quoting this at $50 to $55; WTI 20% over the next three years. Obviously, we've had a lot with EURs and efficiency and expenses and so on. So is just a conservative target at this point, any color there you can give me will be great.

[Harold Hamm:]

I think it's reasonable to assume that if on '17 we have improved $4 from $55 to $51, you can see that at the out years, that's why I made the comment in our comments that we're likely going to see improvement in that. So I expect that we will and as we finalize '18 and looking beyond that, that will be something that will certainly true up. So yes, I'd say we're probably a bit conservative there.

[Unidentified Analyst:]

Okay, got it. And then on the Bernhardt and Blurton test, I think going back away when you originally planned those tests they were intended to be both Meramec and Woodford spacing test, either of those have any wealth in the Woodford and if not, what was the rationale for just doing Meramec?

[Tony Barrett:]

Hi, this is Tony Barrett. Certainly in the Bernhardt unit we did target multiple horizons and we did drill some Woodford in that unit. The Blurton unit is strictly Meramec at this point in time. So all the results we're seeing from those wells right now are Meramec results.

[Unidentified Analyst:]

Okay, thanks.

[Operator:]

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

[Neal Dingmann:]

Good morning. Jack, just kind of staying with the same question on the guys rests on Blurton; can you talk a little bit about just a cumulative -- how the cumulative production compares between the parent and the child well thus far what you're seeing?

[Jack Stark:]

I don't have that here. I think throughout we've described you probably get there so I don't have them in front.

[Neal Dingmann:]

So Gary kind of said the same, I know -- I think you said exactly like 80% of the parent and I think you said the IP was around 2,300; seven childs at 1,200 so I mean we just assume that kind of continue to flow around those rates?

[Gary Gould:]

Yes, the [indiscernible] are increasing. And then fluid production is strong also, and so again, these have to clean up. I think the main point is really what Harold was talking about when we put all this water on the reservoir at one-time, it's really important to get a lot of those full back to be able to tell how these wells are interacting and then Jack talked about the other part, we're just going to look at all these tests, not only ours but all the ones generated by other operators also in order to figure out what the optimum economics is as we develop our many units, or hundreds of units that we have going forward.

[Jack Stark:]

And Neal, I was going to say too; a couple of these well are looking like they are crossing the parent well, coming as far as they are increasing performance or they are lending out with it starting to likely cross it. So like we say, they are still cleaning up and so we just need more time on these unit wells just to get a better handle on performance, the reason we're bringing this out right now, I mean in front of our preference, we would wait another 30 days and talk about this but it was a quarterly and without everybody didn't even want to have an update on what's going on with it and so this is what we have today.

[Harold Hamm:]

And I think this production profile that we've talked about and the loading, these entire units we frac -- all are basically one right off the other. And then flow entire unit. I mean this is not something that we're just seeing in STACK, we see this in SCOOP, we see this in the Bakken as well.

[Neal Dingmann:]

And Harold, is this likely, I mean because this just massive HVP position you have, you now have the advantage of doing this versus a lot of the newer entrants in these plays?

[Harold Hamm:]

Well, yes, we do it for severals. The efficiency gains that you get and all that Gary talked about at this minute.

[Gary Gould:]

No, I think that's a key point that Harold and the other execs have talked about how we're mostly HBP. And so therefore we're able to test these things early because we're going into development mode faster than some of the other operators out there.

[Neal Dingmann:]

Got it.

[Jack Stark:]

And I'm just going to say, and you might have noticed too is that we've got seven densities going on and six of those are full units. Many of those going on out there and I mean the industry is starting to do more of those, and so you've got really bounded units, so wells in these units; so you have a good handle on what performance could be and so -- or will be in these units. And so just know that these are full unit developments.

[Neal Dingmann:]

Okay. And Jack just one last one, I might have missed this. Did you mention the total STACK rig is broken down between like the gas window on the STACKED oil window and doing such kind of JV?

[Jack Stark:]

You mean where the rigs are?

[Neal Dingmann:]

Yes, Sir.

[Jack Stark:]

Right now we've got what nine rigs out there and three of them are targeting Woodford and six or seven, excuse me, two; go ahead.

[Pat Bent:]

This is Pat Bent. Of the nine rigs we currently have in STACK, two are in Woodford and the other seven are targeting Meramec.

[Neal Dingmann:]

Got it, got it. Thanks so much for the details.

[Operator:]

Thank you. Our next question comes from the line of John Freeman with Raymond James. Your line is open.

[John Freeman:]

Hi guys, thanks for squeezing me in here at the end. Just a few questions related to the Bakken Duck, just -- first of all, I just want to make sure that I'm looking at this on an apples-to-apples basis but you've got the four rigs you're running in the Bakken in the second half of the year which is the same as the original guidance and obviously you're going to have 20 more ducks, so just kind of a simple math is about 14% efficiency improvement from what you all just guided last quarter. So, I guess first I just want to make sure that I'm looking at that right and that's apples-to-apples comparison.

[Harold Hamm:]

I'm not sure if I followed it completely, but I'll try to answer that question. So just for the Bakken year-end 2016 we had 190 DUCs and currently at the end of second quarter we had two hundred five. And right now, we're estimating the year end we'll have a 160 and so we still got a great balance which we have to grow into next year also and then as far as the drilling side Pat?

[Pat Bent:]

Yes, this is Pat Bent again. On the drilling side, we've seen just tremendous improvements in our cycle time efficiency and so each rig. For the second quarter, we averaged just under twelve days so right over eleven days from spud TD on four rigs and so if you extend that out over to full year 2017 well rig release was a little bit over one hundred 108 wells in 2017 from a drilling perspective.

[John Freeman:]

Okay. And then just one follow-up for me if I look at despite the pretty decent reduction in the number of fractures up in the Bakken, you are still bring it online basically the same number of wells, the other difference is that in that DUC backlog as previously mentioned instead of having roughly 72 of those DUCs that have been previously stimulated, it will be about 35 now at year end. And should we just sort of think about that as being kind of the first toggle that you all use on CapEx in the near term based on if the commodity price theoretically weakens more from here or strengthens.

[Harold Hamm:]

I think that’s a fair statement. We spoke to that some in the last quarter when we talked about that exact number you're talking about the amount of capital dedicated to that so we have reduced capital a bit and that's been part of the toggle. We've also reduced rigs a bit because frankly we're getting more per rig than we were before as Pat pointed out so that's fair it's also -- if we see improving commodity prices it's also a toggle the other way where we can bring on your production pretty quickly in a very capital efficient way. So, it was strength coming into this year to strength going into eighteen as well and we feel really good about where we are at rent.

[John Freeman:]

Thanks, guys. Great quarter.

[Harold Hamm:]

Thank you, John.

[Operator:]

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

[Derrick Whitfield:]

Hello, good morning and thanks for squeezing me in as well regarding. Regarding the JV comment earlier could you clarify, if your assets that have been identified for this process and if certain assets are off limits.

[Harold Hamm:]

We have identified properties to go into this process and for result limits, I don't think we have an off limit. We have identified them.

[Gary Gould:]

Well, I just got to say I mean we plan to develop the core and holding for ourselves and so I guess will be very similar to our joint development agreement that we did with SK and we're looking for properties that we can further develop and expand our footprint are non-core now they can become core as we deal with somebody.

[Harold Hamm:]

We've got a tremendous range of assets that meet hurdle rates for a wide array of investors out there whether it be private equity, whether it be more strategic like S.K. and we you know we have a lot of different hydrocarbon mix where you know others may want to participate in that we've got the expertise and a variety of assets so we're very, we've got a lot of interesting stuff, but I don’t think it would be the core of the core.

[Derrick Whitfield:]

Got it. Makes sense. And then going back to the Bakken inventory topic by taking a different angle on resource expansion does the new design, DNC design that you guys have implemented with an increased focus on stimulation at well bore encourage you to revisit existing space and assumptions? I know volume metrics tennis suggests water but is the science are effective halfling suggests tighter.

[Gary Gould:]

This is Gary Gould and that's part of our analysis of what our teams will be looking at and so it's very early and we'll be looking at what type of optimum space it will be, we’ll always be looking at maximizing our rate of return and what's great is when you move the Tykerb up like that in a really time that really solidifies your return for the next few years no matter what it does at far end on inventory. And so that's something our teams update usually in between mid-year and year-end reserves and they're working on at that right now.

[Pat Bent:]

I mean when we're seeing these tighter stages basing wells coming on extremely strong it's clear that we're tying into reservoir rock that we did not tie into before, so we're distributing the sand along the wellbore in a much more effective manner and not maybe reaching out as floor. And so, I agree totally with what you are thinking is that would you, could you see there a change in density either greater density or perhaps less but I think greater density because you're more effectively stimulating the rock around the wellbore? And I think that we're very keenly monitoring and looking at that as one of the options in here.

[Derrick Whitfield:]

Got it. Last question for me on the Springer could you comment on the broad testing objectives for Celeste and the thickness of the spring in that area?

[Gary Gould:]

I believe Tony the spring is about 75-foot thick I believe on average and then the in the idea here is to you and get a test with these six wells and just see what if any level of interference might exist between the wells and really. It's just as we do in any these plays it's got to get out there you can do the math all day long but you've got to get the wellbores in there and start producing them and find out how they actually perform. And so right now we've been nothing but impressed with what we've seen come out of the spring with our new with our optimized dims and I mean we've got four wells that we've completed in here you know and we just talked about here the cash in the you know in our -- the barbinson well and both of them are just head and tails above our old nine forty type curve. And so, I think that's in our rearview mirror and it's just a question of what are we going to have is tight curve going toward and what kind of recovery can we expect to get out of this reservoir. But it's huge it's -- this reservoir doesn’t produce any water it's80%, 85% oil and its very well pressured and I mean it’s just an excellent reservoir. So, what we are doing right now is trying to understand get all the knowledge we can so when we go into development we're not leaving any oil behind.

[Derrick Whitfield:]

They are good tales guys.

[Harold Hamm:]

Thank you.

[Operator:]

Thank you. Our next question comes from the line of Joe Allman with FBR. Your line is open.

[Joseph Allman:]

Thank you. Hi, everybody. First one to Harold. You talked about a lot of accomplishments on this but, the company being 50 years old that’s a huge accomplishment. So, congratulations on that.

[Harold Hamm:]

Thank you, Joe.

[Joseph Allman:]

On the Bakken, when you talk about the new tight curve does that represent just the recent wells that you have drilled or is that the average type curve for all future wells assuming the same lateral length or is it just the average type curve for a limited amount of wells within a certain geographic footprint.

[Harold Hamm:]

Well, if you look at the type curve and I think we're going to tell you this on the chart I mean this represents all of our 2017 completions that have been done whether it be H.P.V. wells or grassroots density wells where we're developing out the entire section after the first well. And so, it really represents a large set of wells. Then as far as going forward, we expect this to represent our -- going forward also and we continue to watch this the EUR trends over time with just limited data. It's a challenge to estimate what those EURs are going forward. But again, when we’re talking about an extra $2 million per well in revenue in the first six months, so that's big. You’re tackling, accomplishing, increasing the economics up front in these wells and so the economics will actually prove quicker than EUR in time.

[Gary Gould:]

And Joe regarding the as this is a limited area if you take a look at Page 11 we put that in her specifically to show that we're not just looking at just a localized high graded set of wells. Here you can see this includes wells that are if you go there are Holstein area there northeast corner of Mackenzie County it's thirty miles west over the Garfield's and forty miles to the south of the Holsteins. And so, I mean we're talking about getting this outcome over a broad area and it's…and we're not done. I mean we're continuing to push the extent of where this is for replying optimized completions. So, there's a lot of questions about the inventory and how much of the 1.1. will ride now. The footprint continues to grow and we couldn’t be more pleased with what we’re seeing here. I mean here we’ve been in this play really we started out in 2003 and I remember having some conference calls with you just to talk about the Bakken way back when we first got into it. It was like a webcast and here we are bringing on record wells and what is it what fourteen years later. It's amazing and so this is where technology has taken us drilling times are just I mean going through the floor. I mean it's just these guys are doing I mean they're drilling 25 wells a year out here per rig. It's just unbelievable and then stimulation technology is just taking the performance and obviously the flow back and artificial of all that is really doing everything he can to increase the net present value of these assets and so there's been a big step function change with what we're doing here.

[Joseph Allman:]

And it's very clear and just a follow-up. So, looking on at that map on Slide 11, so there is a lot of acreage in say Central Wayne County and Northern Wayne County and you're up in the divide. So, just as a caution we should necessarily use that 1.1 million Boe across all your acreage because some of it is going to be more productive and some of it is going to be less productive. So, it's one and then second, how much should we think about like infill drilling. The Bakken as you just said is 14 years old and how much degradation might you see as you go forward because you'll be drawing some inter wells as well not just converging wells.

[Gary Gould:]

Hi, this is Gary Gould and as far as the infill wells again this this particular this type curve is based on all wells. HPP, wells as well as those wells that we develop out from grass roots and that's 90% of what we have left to develop. There are not very many units we have out there at this point that still need development with pure infill wells. And so I think this applies and then as far as how do you approach this across a huge area I mean there are differences from one area to the other but what I would say is the factor of improvement that you're seeing will apply everywhere and so the factor improvement and you are the factor of improvement and can be and the factor in the present value and the factor of improvement in a payout rate of return those factors of improvement I think will occur everywhere because the process that we are applying we will apply everywhere as far as larger more complex fracturing and then also the higher capacity artificial lift in more aggressive format.

[Joseph Allman:]

Got you. Very helpful. Thank you, guys.

[Gary Gould:]

Thanks Joe.

[Operator:]

Thank you. And our next question comes from the line of it David Deckelbaum with KeyBanc. Your line is open.

[David Deckelbaum:]

Hi guys, sorry to extend the call. I just have one question. The DUCs have been a huge asset for you all in 17, sounds like it’s going to be going into 18 up in the Bakken. As you start working down a DUC backlog and you approach this idea of free cash neutrality and growth is there an implication in the model where you start ramping up that rig count at the end of eighteen back in the Bakken to start replacing that backlog or does the program become more heavily weighted toward scoop stack over time on the rate of return basis?

[Gary Gould:]

I think that's a fair question there is a point where you get the DUCs back to a norm, the norm because they're on pads and in the Bakken for instance it’s probably around I don’t know 10 DUCs per rig, that fluctuates just with these efficiencies that we're garnering it's tremendous how quickly they're drilling some of these wells and how efficiently they're doing it. So that that is a fluctuation, but ultimately you will bring the DUCs down to a level that is what we’ll consider the norm and then with that you will see a shift from completion to more of a drilling complete environment so that would denote some rig activity and some ring increases but that's out there a little bit.

[David Deckelbaum:]

Thanks for the colors there.

[Gary Gould:]

Absolutely. Thank you.

[Operator:]

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

[Warren Henry:]

Thank you, Kelly. We let the call little long this morning, because we had so many excellent accomplishments in the quarter to talk about and we wanted to take all your questions. So, we appreciate you hanging in there with us. We thank you for joining us today and we look forward to following up with you further on our second quarter results. Have a great day.

[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.