U.S. Markets open in 9 hrs 5 mins

Edited Transcript of CLR earnings conference call or presentation 8-Nov-17 5:00pm GMT

Thomson Reuters StreetEvents

Q3 2017 Continental Resources Inc Earnings Call

ENID Nov 11, 2017 (Thomson StreetEvents) -- Edited Transcript of Continental Resources Inc earnings conference call or presentation Wednesday, November 8, 2017 at 5:00:00pm GMT

TEXT version of Transcript

================================================================================

Corporate Participants

================================================================================

* Gary E. Gould

Continental Resources, Inc. - SVP of Production & Resource Development

* Harold G. Hamm

Continental Resources, Inc. - Executive Chairman & CEO

* J. Warren Henry

Continental Resources, Inc. - VP of IR & Research

* Jack H. Stark

Continental Resources, Inc. - President

* John D. Hart

Continental Resources, Inc. - Senior VP, CFO & Treasurer

* Pat Bent

Continental Resources, Inc. - SVP of Drilling

================================================================================

Conference Call Participants

================================================================================

* Andrew Elliot Venker

Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil and Gas Exploration and Production

* Bradley Barrett Heffern

RBC Capital Markets, LLC, Research Division - Associate

* Brian Michael Corales

Scotia Howard Weil, Research Division - Analyst

* Derrick Lee Whitfield

Stifel, Nicolaus & Company, Incorporated, Research Division - MD & Senior Analyst

* Douglas George Blyth Leggate

BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research

* Eli Kantor

* Jamaal Dejon Dardar

Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Associate, Exploration and Production Research

* Kashy Oladipo Harrison

Piper Jaffray Companies, Research Division - Research Analyst

* Leo Paul Mariani

National Alliance Securities, LLC, Research Division - Research Analyst

* Neal David Dingmann

SunTrust Robinson Humphrey, Inc., Research Division - MD

* Subhasish Chandra

Guggenheim Securities, LLC, Research Division - MD and Senior Equity Analyst

================================================================================

Presentation

--------------------------------------------------------------------------------

Operator [1]

--------------------------------------------------------------------------------

Good day, ladies and gentlemen, and welcome to Continental Resources Third Quarter 2017 Earnings Conference Call. (Operator Instructions) As a reminder, today's conference may be recorded. I'd now like to introduce your host for today's conference, Mr. Warren Henry, Vice President, Investor Relations. Sir, please go ahead.

--------------------------------------------------------------------------------

J. Warren Henry, Continental Resources, Inc. - VP of IR & Research [2]

--------------------------------------------------------------------------------

Thank you, Liz, and good morning to everyone joining us today. We'll start today with remarks from Harold Hamm, Chairman and Chief Executive Officer; Jack Stark, President; John Hart, Chief Financial Officer. And then also on the call and available for Q&A later will be Jeff Hume, Vice Chairman of Strategic Growth Initiatives; Tony Barrett, Vice President, Exploration; Pat Bent, Senior VP of Drilling; Gary Gould, Senior VP, Production and Resource Development; Steve Owen, SVP, Land; and Ramiro Rangel, SVP, 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 SEC filings for additional information concerning these statements and risks. In addition, Continental does not undertake any obligation to update forward-looking statements made on this call. Also, this morning, we will refer to initial production levels for new wells, which 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 that, I will turn the call over to Mr. Hamm. Harold?

--------------------------------------------------------------------------------

Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [3]

--------------------------------------------------------------------------------

Thank you, Warren. As investors saw in our third quarter earnings press release yesterday, Continental reported stellar results across-the-board in all plays.

Again, we have tremendous operating results to discuss with you in STACK and SCOOP, but this morning, we want to focus your attention on the Bakken in North Dakota due to the very impressive results we're seeing in that play year-to-date. These results allow me to shine a spotlight on the very important milestone Continental has just achieved. In late October, we surpassed 300,000 BOE per day of production for the first time in our company's history with 59% of production being oil. Yes, this is a higher number than you've seen in our updated guidance and reflects increases that can occur in our production due to pad development. However, each milestone provides a stepping stone of growth for Continental and for you.

Let me put this in clear context. Five years ago, in November 2012, we announced a plan to triple production to 300,000 BOE per day by the end of 2017. And despite the downturn in oil prices and its inherent challenges of the past 3 years, we've done it, and we did it in very good fashion. What's most amazing is how Continental achieved this historic milestone. Compared with the 2012 5-year strategic growth plan, we achieved 300,000 BOE per day of production with $10 billion less CapEx than planned and with half as many operated wells completed since 2012.

Another amazing fact. When we announced our 2012 growth plan, we envisioned needing 75 operated drilling rigs to get to 300,000 BOE per day level. Instead, we peaked at 52 operated rigs and hit the target with only 18 operated rigs in year 5, substantially less than what we originally anticipated. Again, it clearly shows the amazing efficiency gains accomplished since 2012 by this team.

So let's dig into the Bakken. The Bakken continues to demonstrate it is one of the highest value-generating crude oil plays in North America, and it just keeps getting better. Unit economics, due to optimized completions, high-efficient drilling, infrastructure pipeline build-out and continued reductions and differential, clearly puts this play at the top of the ladder. On top of all that, our third quarter operated daily production increase year-over-year of 35% and sequential quarter-over-quarter increase of 18% has been the primary driver of Continental's new production record of 300,000 BOE per day and has driven Continental to be the uncontested #1 producer in the Bakken.

I think it's fair to say that total improvement just in the last 12 months in the Bakken has surprised many in the U.S. industry, and the improvement in last 36 months has surprised many in the entire world. In addition, the Bakken is the only pure oil play in America where in-fill trial wells, uplift and outperformed the parent well and the unit. Most exciting of all, we're just in the early maturation stage in the play. As Jack will explain in detail, these improved unit economics in the Bakken have significantly increased our long-term inventory depth. Bottom line, we have decades of work to do to develop it fully.

Continental has just begun releasing our pent-up potential. As you're aware, we held back completing wells in the Bakken while the oil market was oversupplied, also chose not to develop the prolific oil-rich Springer at the prevailing prices during the first portion of 2017. The company will be in excellent shape to begin development of this HBP property when prices become stabilized and sustainable, when supply/demand balance corrects.

Now our primary focus today is to work down our Bakken DUC inventory. This is driving higher oil production as a percent of our total company production to 58% in the third quarter, rising to 60% in September before persistent rainy weather curtailed some Bakken production. We began the year with 187 DUCs in the Bakken. We have only harvested 36 gross DUCs on a net basis due to proficient operations at both drilling and completions, leaving an estimated 151 DUCs at year-end. We're using optimized completion techniques on all of this well inventory with great results, setting us up for 33% to 38% year-end exit rate growth over fourth quarter 2016. In addition, back in Oklahoma, Jack will provide color on a few of the best-in-class field completions in STACK, SCOOP for the current quarter.

Company-wide, the key third-quarter takeaway is the degree to which improved performance in the Bakken STACK and SCOOP is enabling Continental to transform itself into one of the highest rate-of-return-energy companies in the United States. We remain solidly on track for cash-neutral growth through the year -- as promised -- and continue to work diligently to sell nonstrategic assets to reduce long-term debt to a $5 billion target. The key is continuing to raise the number of barrels produced per dollar invested within budget and cash flow. We expect to further improve recent capital efficiency plans due to the unparalleled quality of our assets and depth of inventory. We are executing at a very high level in all plays with great efficiency.

The other critical variable, of course, is the macro picture for oil as world markets continue to rebalance. The U.S. continues to gain access to foreign markets. Export from the U.S. were over 2 million barrels of oil per day as of the last week in October. Continental has introduced the very high-quality sweet Bakken crude to the Asian markets. We have found keen interest in this grade of oil and it is highly valued. We expect our recently announce a million barrel sale to be the first of many more to come.

Now some have expressed concern, U.S. shale producers could spoil the party by overproducing, but we just haven't seen that happen. This is a key reason we've been pointing out EIA annual forecasts are too high. The most recent monthly actual reported last week was 9.2 million barrels a day for August. We see only movement from the current 9.2 million barrels of oil per day to 9.35 million or 9.4 million barrels of oil per day by year-end, not the 9.7 million barrels of oil per day level projected by the EIA in their last-minute report. The overblown forecast for U.S. production tends to disadvantage the U.S. market and puts America last, not first. The EIA must take actions to correct this problematic forecasting system in the near future. With moderating production and continued solid demand, U.S. inventories are therefore coming down, and we expect they will keep doing so. Inventories are approaching the 5-year average.

Looking specifically at Cushing, we expect new pipeline takeaway capacity of 200,000 barrels per day will further deplete storage in Oklahoma. [Diamont] pipelines have begun filling now, which will also take oil from Cushing and should enhance WTI prices relative to Brent price spread difference.

The oil macro picture continues to improve. It's refreshing to see the investment community and analysts turn attention to the macro environment, rewarding companies that are disciplined in their spending and who focus their attention on commodity market supply and demand in the world. Continental's management has long been focused on the restoration of balance of the supply and demand, and for far too long, I've been a lone voice in the forest. Remember, the largest investor at Continental is a strong proponent of shareholder value enhancement. At Continental, we've been living within cash flow the last couple of years while retiring debt.

So let me summarize. Continental once again delivered great results this quarter, and the company is positioned to deliver cash flow positive double-digit production growth. This is net effect of the continuous improvements we have reported quarter-after-quarter over the last couple of years. Thanks to technical innovation generated by our teams and our high-quality geologically superior assets, Continental now ranks as one of the lowest-cost operators with one of the highest unhedged margins and recycle ratios among our oil-related peers. Today, we're delivering 2 to 3x of barrels per dollar invested than we did in 2014. We look forward to a very strong fourth quarter and a new year, so stay tuned. Our goal is to deliver top-shelf shareholder returns as markets improve.

So with that, I'll turn the call over to Jack.

--------------------------------------------------------------------------------

Jack H. Stark, Continental Resources, Inc. - President [4]

--------------------------------------------------------------------------------

Thanks, Harold, and good morning, everyone. Thanks for joining our call. As Harold said, we had a tremendous quarter, and I have some impressive results to share.

I'll start with some of the biggest news in the quarter that comes from the Bakken. We're now convinced that our optimized completion technology has expanded and upgraded the economics of our entire Bakken inventory. This is one of the many technical breakthroughs we have seen in the Bakken over the last 15 years. Each breakthrough has raised the level of performance and economics throughout the field. Our optimized completions are clearly contacting more reservoir rock than ever before, increasing production rates and recoverable reserves.

The proof is in the results. During the quarter, we completed another 57 optimized Bakken wells with average initial rates of 1,750 BOE per day and 80% of the production was oil. In total, we have completed over 100 optimized wells through the third quarter, and on average, these wells are performing in line to slightly above our new 1.1 million BOE type curve. What's impressive is these wells are located across the broad cross section of our acreage. This gives us confidence the results we're seeing are not isolated but a step-function change in the field through technology.

So what's the net impact to Continental and to shareholders? More value from our tremendous Bakken assets. Our new type curve announced last quarter included a 12% increase in EUR, but more importantly, double the rate of return to 80% and a $50 WTI. This translates to an impressive $2 million of incremental gross cash flow per well during the first year and cuts payouts in half to 15 months. This is a key driver to achieve our plans for cash flow positive growth in oil-related growth.

This breakthrough comes at a good time considering we are in the early stages of development in the Bakken. We have approximately 1,600 gross operated wells producing in the Bakken at this time with over 4,000 gross operated Bakken locations remaining in inventory. This is a high-quality, multi-decade inventory. To give you some perspective, the company could reasonably expect to drill about half this Bakken inventory over the next 10 years, assuming an average operated rig count of 8 to 10 rigs. During this time, we believe this inventory could deliver an impressive blended rate of return of 60% to 80%, assuming $50 to $55 WTI. The blended rate of return for 2018 should even be higher as we expect to have approximately 151 DUCs that deliver over 150% rates of return on a cost-forward basis to blend into the 2018 drilling program.

On top of this good news, our oil differentials in the third quarter in the Bakken improved by over $2.50 per barrel compared to the first quarter 2017 and look to be trending even lower in the fourth quarter. Likewise, our drilling time to cost continue to decline, and we are fast approaching a new standard of 24 wells per rig per year. This means we're getting almost 50% more wells per rig per year than we did on average in 2014. So the bottom line is the economics and recovery from the Bakken, the one true oil play here in the U.S., continue to get better through technical innovation 15 years after its discovery.

Now let's move to Oklahoma where we continue to achieve record results. I will start in STACK with impressive results from our 10-well Compton density test in Blaine County. The 10 wells delivered a combined maximum rate of 16,400 barrels of oil per day and 33.7 million cubic feet of gas per day or over 22,000 BOE per day with 75% of the production being oil. This was a full unit density test with 5 wells in the Upper Meramec and 5 wells in the Lower Meramec, including one parent and 9 children wells. On average, lateral length was approximately 10,200 feet per well.

Early performance of these wells, on average, is in line with our 1.7 million BOE type curve for the oil -- overpressured oil window. Efficiency gains from pad development reduced drilling times and completed well costs for the Compton children wells by 52% and 28%, respectively, compared to the parent well. Now to guide future development, we have 3 additional Meramec density tests completing at this time, including 2 full unit density tests in the oil window and one partial unit test in the condensate window. We expect to have results from these density tests in the coming quarter.

In our release, we also announced 7 stand-alone Meramec wells of STACK with average initial rates of 3,736 BOE per day with 40% being oil. Three wells of note include the R Moore 1-24H, the Edward Lee 1-13-12XH and the Lorene 1-8-5XH. The R Moore flowed at an impressive rate of 3,565 BOE per day from a 4,900-foot lateral, and 71% of the production was oil.

The Edward Lee, our first Meramec completion in Dewey County, flowed 10.8 million cubic feet of gas per day and 54 barrels of oil per day at 4,500 psi flowing tubing pressure. This is our farthest west completion in the overpressured STACK to date located 35 miles west of our Verona-Gillilan pad. It is also a key test as it derisks a good portion of our acreage in Dewey County.

Last, but not least, our recently completed Lorene well has set a new initial 24-hour rate record for horizontal wells in Oklahoma. The Lorene produced a remarkable 6,715 BOE per day at 5,575 psi flowing casing pressure from a 10,200-foot lateral. This included 1,863 barrels of oil per day and 29 million cubic feet of gas per day. On a 3-stream basis, Continental estimates the initial 24-hour IP rate for Lorene to be a record 8,347 BOE with 53% of the production being liquids. This exceeds the record rate announced by the company in August for the Tres C well.

And during the first 30 days of Tres C, it produced approximately 160,000 BOE, averaging 5,345 BOE per day with 15% of the production being oil. The Tres C is currently flowing around 3,600 BOE per day at 3,375 psi flowing casing pressure. Of note, the Lorene is located about 2 miles east of the Tres C. The key point here is that the Tres C results are repeatable, which highlights, really, the tremendous resource potential that exists in STACK.

Now moving on to SCOOP, we also have record production reports from our fifth dual-zone Woodford density test in the Sympson unit located in Stephens County. The unit flowed at a combined initial rate of 222 million cubic feet of gas per day and 4,650 barrels of oil per day with an average flowing casing pressure of 3,100 psi. This is the highest combined rate we have found from a horizontally developed unit in Oklahoma to date and once again highlights the tremendous resource potential that exists in both SCOOP and STACK.

Now Sympson is a 10-well pattern, dual-zone density test with equivalent of 5 2-mile laterals in the Upper Woodford and 5 2-mile laterals in the lower Woodford in this 1,280-acre unit. This includes 2 parent wells that are under 1 mile long and 3 children wells ranging from 3,050 feet to 10,270 feet in length. Now I recognize it may be confusing that this is a 10-well density that includes 14 wells but 12 children wells of various lengths were needed to fill out the 10-well 2-mile long pattern, and we've provided a diagram on Slide 16 for details. The average flowing rig for the 12 children wells was 3,145 BOE per day with 11% being oil.

As in the Bakken, we optimized the completion of the Sympson unit. The Sympson unit wells were completed using our latest technology with an average of 200 versus 300-foot stage spacing and approximately twice the proppant volume used in our first 10-well density test in the Poteet unit. [Early] time the optimized Sympson unit is outperforming the nearby Poteet unit approximately 20% on an Mcf per foot basis; and that's per lateral foot.

With the Sympson, we now have 2 8-well and 3 10-well, dual-zone density units completed and producing in SCOOP Woodford. All have been outstanding producers in the DUC by dual-zone development, where the Woodford is greater than 250 feet thick. Over 50% of our acreage in SCOOP Woodford is greater than 250 feet thick, so the resource potential from this acreage is clearly tremendous. It gets even better when you realize that some of this acreage will get a double dip with development of the overlying Springer oil reservoir as well.

Speaking of the Springer, our Cash, Trammell, Strassle and Robinson wells continue to outperform our legacy 940 MBoe Springer type curve by an average of 70% at 150 days. As a result, we expect to revise our legacy Springer type curve to reflect this improved performance in the coming quarter. Our 6-well Springer density test in the Celesta unit has been drilled, and completion work is now underway. First production is expected late this year or early first quarter 2018. We're very pleased with the results of our testing in the Springer this year, and with improving crude prices, the Springer is likely to be in our 2018 drilling plans.

I will close my portion of the call now by reiterating the operating efficiencies and technologies we've developed over the last couple of years are unleashing the true potential of our superior geologic assets. The third quarter results continue to translate that potential into reality, reinforcing our vision to remain a low-cost leader among our peers while delivering cash flow positive double-digit growth.

So that concludes my operational update, and I'll turn the call now over to John.

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [5]

--------------------------------------------------------------------------------

Thank you, Jack. Good morning to everyone with us today. We're pleased to update you on our third quarter results while also briefly touching on 2018.

Our third quarter results were extremely impressive. Despite unforeseen weather issues in the north, we still had quarter-over-quarter production growth of approximately 7% with a big chunk of that growth being oil growth while improving operating costs and maintaining capital spending in line with budget and cash flow.

Revenue for the third quarter was $727 million, and net cash provided by operating activities was $431 million. Net income for the third quarter was $10.6 million or $0.03 per diluted share. Adjusted to exclude impairments, noncash gains and losses on derivatives and gains and losses on asset sales, our net income would've been $32.2 million or $0.09 per diluted share for the third quarter. EBITDAX was $564 million for the quarter.

Third quarter production came in at 242,800 BOE per day with 58% of our production being oil. Without the weather interruptions, we estimate we would've produced over 246,000 BOE per day for the quarter. During October, we averaged 59% oil even after bringing on the sizable density pilots in Oklahoma we announced today.

Let me provide additional color. We expect oil volumes will be 14% to 18% higher in Q4 versus Q3, representing further strong oil growth. We're projecting fourth quarter production to be approximately 275,000 to 285,000 BOE per day with 59% to 60% oil. Our updated exit rate guidance is 280,000 to 290,000 BOE per day. As you can likely see by the guidance for Q4, it's about more than just the hydrocarbon ratio, but also absolute volumetrics, which drive cash flow.

[Con] acquisition capital expenditures for the third quarter were $521 million. With the improvement in commodity prices the past few months, we expect our capital budget to be in line with our original capital budget of $1.95 billion and also to be cash flow positive for the year once you include the proceeds from our previously announced divestitures. Excluding those divestitures, we expect to be cash neutral to cash positive for the year.

Production expense decreased to $3.82 per BOE, down from $3.99 per BOE last quarter. Third quarter cash G&A, excluding equity compensation, was an impressive $1.45 per BOE. Noncash equity compensation was $0.54 per BOE for a total G&A of $1.99 per BOE. Select cash costs, including lease operating expense, production tax, cash G&A and interest expense, came in at $10.97 per BOE for the third quarter, slightly lower than the second quarter, another solid quarter exemplifying our low-cost structure and showcasing our strong margins. I would expect this to continue to improve as production picks up next quarter.

Oil differentials were also lower in the quarter, coming in at a negative $4.98 per barrel, reflecting a full quarter with the new Dapple pipeline operating in the Bakken as well as improving differentials in Oklahoma. Corporately, this was a quarter-over-quarter improvement of $1.33. We expect additional improvement over the next several years as Continental's existing transportation contracts get renegotiated or roll off and as additional infrastructure is developed in Oklahoma. Near term, we expect the fourth quarter oil differential to be between $4.25 and $4.75 per barrel on a company-wide basis. Natural gas differentials also improved for the quarter and were a positive $0.02 for the month of September due to improved NGL pricing. We're continuing to see NGL price strength.

At the end of the quarter, we closed on previously announced asset sales of $76.1 million. The remaining sale announced last quarter closed in October, and $59.9 million of proceeds from the sale will be reflected in the fourth quarter financials. As of September 30, long-term debt was $6.6 billion. Our near-term goal is to reduce debt to $6 billion or lower and then to reduce debt further to $5 billion within the next few years. We currently have a few packages being marketed that have garnered strong interest among a wide group of parties, and we feel comfortable that we will be able to attain our current debt target of $6 billion in the near term and then $5 billion subsequently.

As additional color, I would like to reference our leverage metrics. Based on strong production and better commodity prices, our leverage ratios are improving dramatically. Annualizing the third quarter results, debt to EBITDAX would be 2.93x, dropping below 3x. And looking forward, we expect the fourth quarter annualized debt to EBITDAX will be below 2.5x, assuming current commodity prices and our expectations for fourth quarter production. This is a significant improvement, driven by expectations for strong oil-weighted production growth and higher commodity prices. Our goal is to be between 1.5x and 2x debt to EBITDAX and to reobtain our investment grade rating. Our trajectory is strong.

Throughout the year, we have attempted to provide transparency and color related to our multiyear outlook. I would like to take a moment now to update you. We anticipate announcing our 2018 capital budget and operating guidance early next year. We're currently working through a variety of scenarios and are pleased with how our plans for 2018 are evolving.

Let's discuss some of the underlying concepts in our planning. Our 2018 goal is focused on capital discipline and maximizing shareholder value. In the current commodity price environment, we're targeting strong positive cash flow with annual production growth between 15% and 20%. Excess cash flow will be applied to further debt reduction. We can execute our plans in a variety of price environments. For our modeling, we have utilized a range of prices between $50 and $55, as noted in prior quarters. However, due to our well productivity and our lean cost structure, we can also generate solid results below $50.

We will also continue to focus on our return on capital employed. Over the previous 10 years, our average yearly return on capital employed was approximately 20%. This is amongst the industry leaders. While recent years have been lower with oil price declines, we have adjusted. And based on improved well productivity, our low-cost structure and exceptional margins, we are seeing continued improvement and anticipate strong results in 2018 as we continue to prioritize returns.

Additionally, our stock is up in excess of 250% during this 10-year period, again amongst industry leaders. Obviously, a focus on returns and shareholder value is not new to CLR. What has evolved is while, historically, certain periods required a level of outspend as we accelerated production or worked to hold acreage, that is no longer the case today. Our go-forward strategy is cash flow positive growth.

Our plans for 2018 are continually evolving, and these reference points are only meant to demonstrate that we are well positioned for 2018 to deliver strong results, not only next year, but in subsequent years that follow. The bottom line is our focus will be to generate positive cash flow with strong capital-efficient production enabling that cash flow.

With that, I'd like to turn the call back over to Harold.

--------------------------------------------------------------------------------

Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [6]

--------------------------------------------------------------------------------

Thanks, John. I just want to reiterate for you today the fact that Continental is ideally positioned for positive cash flow production growth at this particular juncture in time. We have fully transitioned from exploration mode as we laid claim to some of the best assets in the U.S. Today, these assets are essentially secured and ready to harvest. In particular, Continental is heavily invested in 2 of the best oil plays in America, the Bakken and the oil-rich Springer play in Oklahoma, with decades of inventory to develop. We have been living within cash flow for the past couple of years as we steered the company safely down the road, focusing on shareholder value and debt reduction as the market rebalanced.

There have been a lot of interest in incentive compensation as of late, so let me save you the question. We have always had a focus on returns within our compensation metrics. We are in discussions with our Board and Compensation Committee regarding our metric for 2018 and are focused on multiple returns-based metrics. This is an ongoing discussion, and we will have more to report on next year. But let me assure you, there's no other CEO that's more aligned with the investment community. And once again, being the largest investor at Continental, I'm a very strong proponent of building shareholder value.

Thank you for your interest in Continental Resources.

With that, we're ready to begin the Q&A section of our call. Operator?

================================================================================

Questions and Answers

--------------------------------------------------------------------------------

Operator [1]

--------------------------------------------------------------------------------

(Operator Instructions) Our first question is from the line of Drew Venker with Morgan Stanley.

--------------------------------------------------------------------------------

Andrew Elliot Venker, Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil and Gas Exploration and Production [2]

--------------------------------------------------------------------------------

You guys talked about potential free cash flow being very strong, and I think we definitely agree with the numbers on that front. So just curious if you can give some more color on how you prioritize between growth, because you have a lot of very attractive assets to invest in, relative to the free cash flow you could be generating and how you guys set along that 15% to 20% growth.

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [3]

--------------------------------------------------------------------------------

15% to 20% is a good, strong growth for next year, and we'll also be working to set up for 2019 beginning to move beyond just DUCs in the Bakken, getting those back to normal, more of a normal drilling complete. So we're comfortable in that range. It could move slightly one way or the other. Excess cash flow coming off that, I think -- that's a good rate. And the excess cash flow off that, we're going to apply to debt reduction. Prices may move up slightly, but that gives us more to apply to debt reduction. We think that's very shareholder-friendly.

--------------------------------------------------------------------------------

Andrew Elliot Venker, Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil and Gas Exploration and Production [4]

--------------------------------------------------------------------------------

Yes, I would absolutely agree with that. John, just, I guess, to follow up with that. Is that 15% to 20% growth for '18, you think, a good target, a good starting point for 2019 and the years beyond that?

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [5]

--------------------------------------------------------------------------------

Yes. The 2018 budget will include not only the amounts that generate that, but it will include some capital amounts that are setting us up well for '19. You have to remember the bulk of our assets around large pads, very capital-efficient pads again, but -- so some capital next year, we'll -- you'll see the production results for it in 2019. So we take a multiyear look.

--------------------------------------------------------------------------------

Andrew Elliot Venker, Morgan Stanley, Research Division - VP and Lead Analyst for the Mid-Cap Oil and Gas Exploration and Production [6]

--------------------------------------------------------------------------------

And then John, is there -- or maybe, Harold, makes sense for you to speak to this as well, whether there'd be a point where you think you would transition to using free cash flow to return cash to shareholders, whether buybacks or dividends at some point once you hit that target leverage you were speaking to?

--------------------------------------------------------------------------------

Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [7]

--------------------------------------------------------------------------------

Well, buybacks may make sense if you get to that point where that could happen. Basically, we'd been in a situation that -- we'll be -- the first situation we'll deal with is debt reduction, and so that's our first focus.

--------------------------------------------------------------------------------

Operator [8]

--------------------------------------------------------------------------------

Our next question comes from the line of Brian Corales with Howard Weil.

--------------------------------------------------------------------------------

Brian Michael Corales, Scotia Howard Weil, Research Division - Analyst [9]

--------------------------------------------------------------------------------

And maybe just to continue on the past -- last question. I think in the past, you all talked about being cash neutral, and now it's free cash flow. I mean, we're estimating free cash flow next year for you all. Is that just the commodity price increasing that's driving that? Or with the well results that we're seeing or that you all are seeing, is that the main driver?

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [10]

--------------------------------------------------------------------------------

Obviously, the commodity price has come up over the recent few weeks here, and we think it's going to continue with what we're seeing in the supply and demand. But as I noted in the script, we've done that modeling in the $50 to $55 range, really toward closer to the $50 range, and we were able to generate strong results below $50. So I think the production and uplift, the efficiency that we're seeing within the company enables that in a variety of pricing environments. As prices go up, the level of that positive nature continues to increase, but it is significant at $50.

--------------------------------------------------------------------------------

Jack H. Stark, Continental Resources, Inc. - President [11]

--------------------------------------------------------------------------------

Brian, this is Jack. I have to say a lot of it is well performance. I mean, we're seeing, obviously, some improvement in price. But the well performance that we're seeing is just exceptional. And it's -- we're seeing outperformance in all of our plays because of the stimulation work we're doing. And also from a -- just a profit standpoint, the efficiencies are driving costs down still. And so we -- it's a combination of all of it, but a big, big driver especially this year is just the outperformance of our wells.

--------------------------------------------------------------------------------

Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [12]

--------------------------------------------------------------------------------

And then a third component, of course, is the (inaudible) wells. It's something that Continental has that most companies don't have. So that's the other big factor.

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [13]

--------------------------------------------------------------------------------

I think it's productivity and low-cost enable us to compete in a variety of environments and do have exceptionally strong results.

--------------------------------------------------------------------------------

Brian Michael Corales, Scotia Howard Weil, Research Division - Analyst [14]

--------------------------------------------------------------------------------

And it sounds like 2018 -- I guess you will exit this year with 150 DUCs in the Bakken, and those will be down to a normalized level. Can you maybe just -- what is a normalized level with a full rig program? Or is there a rule of thumb with per rig? How many wells should be a good DUC number?

--------------------------------------------------------------------------------

Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [15]

--------------------------------------------------------------------------------

This is Gary Gould. And if we're running 4 rigs right now, we're on pretty large pads. So a range of a normalized DUCs number for 4 rigs probably would be in the neighborhood of 60 or so because we're working on very large pads.

--------------------------------------------------------------------------------

Brian Michael Corales, Scotia Howard Weil, Research Division - Analyst [16]

--------------------------------------------------------------------------------

So we can assume roughly about 100 gross wells being worked down in 2018? Is that...

--------------------------------------------------------------------------------

Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [17]

--------------------------------------------------------------------------------

Yes, that's correct. If we get them all down next year like we currently think we will.

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [18]

--------------------------------------------------------------------------------

It'll continue to be a key part of our '18 plan, similar to what it was in '17. Don't miss that in '17, we completed a lot of wells. We completed more than we modeled. But the drilling efficiencies that the team's captured continued to add to that inventory. So I mean, it's a pretty impressive little asset we've got there.

--------------------------------------------------------------------------------

Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [19]

--------------------------------------------------------------------------------

Yes, and that's with just 4 rigs.

--------------------------------------------------------------------------------

Operator [20]

--------------------------------------------------------------------------------

Our next question comes from the line of Subash Chandra with Guggenheim.

--------------------------------------------------------------------------------

Subhasish Chandra, Guggenheim Securities, LLC, Research Division - MD and Senior Equity Analyst [21]

--------------------------------------------------------------------------------

So last quarter, after the Blurton pad, you guys had talked about comfort with 20% type interference as some sort of constructive interference. I think that was the number you might have put out there. The Compton doesn't appear to have suffered any or seen any, at least from the average result. So curious if you're sort of changing expectations on pads to maybe seeing less than 20%, if the Blurton was a standout or if the Blurton ultimately cleaned up and didn't show the interference that it might have in its early weeks on the 2Q call.

--------------------------------------------------------------------------------

Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [22]

--------------------------------------------------------------------------------

Yes. This is Gary Gould. And the Blurton did continue to clean up for us. So I think last quarter, we were talking about the children wells producing at about 80% of the parent. Those wells continued to clean up. And over the last 50 to 60 days, they're averaging about 85% of the parent. That's within the range that we see. We see a range of about 10% to 20%, not really that 20% you were referring to.

--------------------------------------------------------------------------------

Subhasish Chandra, Guggenheim Securities, LLC, Research Division - MD and Senior Equity Analyst [23]

--------------------------------------------------------------------------------

And the Compton, is the expectation there that you'd see something similar over time or not?

--------------------------------------------------------------------------------

Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [24]

--------------------------------------------------------------------------------

Yes. I think similar over time is what we expect right now. But really, that's why we're doing all these tests. We're doing 8-well tests. We're doing 10-well tests. We're testing completion designs from 1,500 pounds per foot up towards 2,250 or 2,500 pounds per foot. And putting all this together is going to help us find that optimum combination of well density and optimized completion design.

--------------------------------------------------------------------------------

Subhasish Chandra, Guggenheim Securities, LLC, Research Division - MD and Senior Equity Analyst [25]

--------------------------------------------------------------------------------

So in the Compton -- because I think the Blurton, you said that so much fluid went in and it took time to clean up. Was it different -- was the experience different in the Compton? Or were certain tweaks made in the completions that avoided that issue?

--------------------------------------------------------------------------------

Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [26]

--------------------------------------------------------------------------------

Yes, it was experienced different. The Compton came on strong right away. A matter of fact, look at our production rate, we think we've actually got an industry record there as far as initial IP for a STACK pad.

--------------------------------------------------------------------------------

Subhasish Chandra, Guggenheim Securities, LLC, Research Division - MD and Senior Equity Analyst [27]

--------------------------------------------------------------------------------

You're right. And not to belabor it, but I guess is that a pressure issue? Or did you use less fluid, for instance, in the Compton versus Blurton?

--------------------------------------------------------------------------------

Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [28]

--------------------------------------------------------------------------------

Well, for us, it was mostly because we brought all the wells on at one time in the Compton, and so that was a major change and difference between the Compton and the Blurton.

--------------------------------------------------------------------------------

Jack H. Stark, Continental Resources, Inc. - President [29]

--------------------------------------------------------------------------------

And Subash -- this is Jack. And geology obviously played a part in that in how the -- what the relative perm is in the reservoir and how quickly these will come back after stimulation. And so it's a combination of all the factors.

--------------------------------------------------------------------------------

Subhasish Chandra, Guggenheim Securities, LLC, Research Division - MD and Senior Equity Analyst [30]

--------------------------------------------------------------------------------

Got it. No, helpful discussion. And my other question is, any progress there? Or I guess you guys have talked about, in some of your plays, JV-ing some of the more gassy stuff, et cetera, along the lines of what you've done with this SK, et cetera. Is that still something you're working on, you're hoping to achieve?

--------------------------------------------------------------------------------

Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [31]

--------------------------------------------------------------------------------

It is. That's ongoing, and we're having good interest and could be -- seeing something toward the end of the year, I think.

--------------------------------------------------------------------------------

Subhasish Chandra, Guggenheim Securities, LLC, Research Division - MD and Senior Equity Analyst [32]

--------------------------------------------------------------------------------

Terrific. And my final one, guys, is I think you've -- you talked to this last quarter as well -- I just wanted to clarify and make sure the message is the same. So in the Williston stimulations, no change in experience between Three Forks or Bakken, they perform roughly the same?

--------------------------------------------------------------------------------

Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [33]

--------------------------------------------------------------------------------

Well, it varies one way or the other. But certainly, both formations have benefited from the tighter stage spacing. Most of those were about 165 feet now. I think that's been the biggest thing. And so Gary, you want to...

--------------------------------------------------------------------------------

Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [34]

--------------------------------------------------------------------------------

Sure, I can add just a little more to that and said -- on our reference on Page 23, we show this quarter's wells, and we added 3 additional wells to our top 10 list. And one of them was in the Three Forks and 2 of them were in the Middle Bakken. So we continue to see strong results from both the Middle Bakken and the Three Forks. And as Harold was saying, all 3 of those wells were in the range of 140 to 165-foot stage spacing. So we're optimistic about what that can do to continue to raise our performance in the Bakken.

--------------------------------------------------------------------------------

Operator [35]

--------------------------------------------------------------------------------

Our next question comes from the line of Neal Dingmann with SunTrust.

--------------------------------------------------------------------------------

Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [36]

--------------------------------------------------------------------------------

Harold, I couldn't notice -- did certainly notice your and Jack's enthusiasm or continued enthusiasm for the Bakken. You both talked about that initially. I'm just wondering, I know you don't have a full '18 plan out -- you talked about bringing that out later -- but I'm just wondering from an allocation, given the -- I don't want to say improvements, just given the continued improvements we've seen there, thoughts about '18 as far as capital allocation towards the Bakken versus the Mid-Con?

--------------------------------------------------------------------------------

Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [37]

--------------------------------------------------------------------------------

Well, yes. Let me start out and Jack can follow up to it as well. But no, it -- our interest, for sure, this quarter was on the fact of how these wells have performed and continue to perform, continue to get better and so certainly adding back completion crews is the first thing we do. And as far as comparison to the south portion, I'll let Jack go ahead and add color in that.

--------------------------------------------------------------------------------

Jack H. Stark, Continental Resources, Inc. - President [38]

--------------------------------------------------------------------------------

We're going to have a disproportionate dollars next year going in -- I'm just saying, not guidance, but really potentially. With the DUCs that we've got in the Bakken, we're going to continue with our rigs and move in -- move to completing the DUCs, as we have this year. So as a result, we'll be a little more heavily weighted in the Bakken. But we continue to expand what we're doing down in Oklahoma as well, as you can see the play -- plays continue expanding and may require some additional work down there and even with Springer, may be blended in as part of the overall inventory next year.

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [39]

--------------------------------------------------------------------------------

And Neal, I think it'd be pretty similar if you look to '17. We had disproportionate go into the Bakken with the DUCs. The great thing is with the results you've seen today and previous quarters, I mean, obviously, we have a tremendous portfolio to select from and where we're allocating capital. We can obviously grow that oil percentage in a meaningful way as we're showing you here. So it's a good -- there's a lot of good optionality that we have and -- but going after the Bakken DUCs and working those down to normal inventory and shifting into more of a drilling and complete mode in the Bakken, it's certainly earning those dollars.

--------------------------------------------------------------------------------

Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [40]

--------------------------------------------------------------------------------

Great details, guys. And just one follow-up. With the bit of run we've seen in oil prices, Harold, just wondering, your thoughts on hedges here anytime soon or kind of where -- given where we are in the macro environment.

--------------------------------------------------------------------------------

Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [41]

--------------------------------------------------------------------------------

Yes, first of all, we continue to strengthen our hedging team within the company. And I don't think there's anybody that's more up on what's happening on the oil macro than we are here at Continental. As we -- we think there's a little bit more to run here for sure as this market rebalances. So we'll keep a close eye on it. And opportunity, when it comes about, we're going to be there to take advantage of it.

--------------------------------------------------------------------------------

Operator [42]

--------------------------------------------------------------------------------

Our next question comes from the line of Doug Leggate with Bank of America.

--------------------------------------------------------------------------------

Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [43]

--------------------------------------------------------------------------------

I guess John Hart for the first question. John, 18%, maybe a little higher than that, seems to be the math if you hold your exit rate flat as year-over-year production. So help me make sense of the 15% to 20% number year-over-year as a target if your run rate exiting is already at the high end of that range.

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [44]

--------------------------------------------------------------------------------

I think it depends on where you go to that exit rate guidance. I mean, you get -- the low end is probably 15%, the high end is probably 20%. We will -- as we start to go more to drill and complete in the Bakken, it'll take some time to drill those pads, and a lot of that will come on later in the year, which may boost up the exit rate, but on a year-over-year basis won't necessarily change the total volume metrics. I mean, the great thing, Doug, is we've got a lot of optionality. We can flex that up. We can flex that down. But I think that's a pretty good year-over-year growth rate, particularly when you're looking at setting up growth to '19 and '20 and beyond with some of those larger pads that we talked about and putting up a significant amount of positive cash flow. So we're in a good position. We've got a lot of optionality. That's meant to give you a sensitivity of some of the ranges that we're looking at now and also some of the balancing with the positive cash flow and returning that to shareholders in the form of reducing debt. So good range, I think.

--------------------------------------------------------------------------------

Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [45]

--------------------------------------------------------------------------------

I appreciate the answer. Maybe just to elaborate a little bit. Cadence on the production profile for next year, would you care to offer any color there? Would you expect a flat first half or a down first half?

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [46]

--------------------------------------------------------------------------------

We'll come out with that when we -- in early next year when we come out with the capital budget. That's something that we're always working to optimize, and we'll continue to do that. I think you guys will be pleased with the results when we come out with them. And certainly, we have a history of performing very well against our guidance and delivering. And over the last 2 or 3 years, as Harold said, we've done it in a very -- in a cash-neutral type position. And as I referred to, over a 10-year, we've certainly done a tremendous job in terms of returns on capital. So we're setting up well for not only '18, but for several years out.

--------------------------------------------------------------------------------

Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [47]

--------------------------------------------------------------------------------

I appreciate and agree with that, for sure. So my follow-up is for Jack. I guess a conference call, Jack, wouldn't be same if I didn't ask you a type curve question, so...

--------------------------------------------------------------------------------

Jack H. Stark, Continental Resources, Inc. - President [48]

--------------------------------------------------------------------------------

I'm ready. I'm ready. Which one?

--------------------------------------------------------------------------------

Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [49]

--------------------------------------------------------------------------------

Page 22, 23. Clearly, the -- are we evolving into 2 type curves in the Bakken? And how -- maybe if I could ask you, what I'm referring to specifically is the Dunn County area because a lot of those more recent wells, I guess -- I don't know if Dunn County is included in your commentary around recent well performance. But you're obviously performing a little bit above the 1.1 curve already in the northwest area of your acreage. And I guess maybe if you could offer some color on what your marked around the Springer as well, and I'll leave it there.

--------------------------------------------------------------------------------

Jack H. Stark, Continental Resources, Inc. - President [50]

--------------------------------------------------------------------------------

Well, the -- you're hitting on a great point here is that -- I mean, what we're seeing is we're seeing this uplift across the whole play. And I mean -- and you look at the -- just the combined results of the 100 wells we've got producing, and we even have some more that are coming on. I mean, they're definitely supporting our 1.1 million barrel equivalent type curve. And even as you can see on the chart on 22 that you're pointing out, you're seeing that they're -- the -- they're outperforming. But you also look, there's fewer wells when you get out to the right side of the curve there. And so we're just building our base of knowledge here from more and more wells, and as we do, we will adjust. But we couldn't be more pleased with what we're seeing here in the Bakken. And again, it's that broad footprint, I mean, we're seeing it all across our acreage, and then you take into consideration the uplift. Other operators are seeing out here as well from this type of work. And it's clear, the whole Bakken field has been uplifted through technology here in the last year, and it's taken the whole field to another level. And you go to the Springer, really talk about going to another level. We've done the same thing there. I think what pages are...

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [51]

--------------------------------------------------------------------------------

17.

--------------------------------------------------------------------------------

Jack H. Stark, Continental Resources, Inc. - President [52]

--------------------------------------------------------------------------------

Page 17 in our slide deck shows just how the 4 wells we've drilled this year, which were both a combination of -- they've all been stimulated using our enhanced stims. And they're at various lengths, testing our ability to drill longer laterals in here out into thinner areas. And what you're seeing here is just a remarkable outperformance of that type curve. And I did talk to Gary before the call, and I said, "Gary, I think Doug's going to ask us." And so that's why I put them on -- I said that's the reason I put it in my script. I said we are and Gary and his group are looking at this, and we'll be updating the type curve for the Springer. And it will be impressive because of the early time performance that you're seeing on these wells, again, how the Bakken are uplifting the type curve, maybe gave us, what, 12% uplift in EUR but it gave an 80% or double -- an 80% rate of return, so double the rates of return. So I think we're going to see this -- the rates return here in the Springer look really strong as well and see a nice increase there, which is, again, just plays just perfectly into our ability to generate free cash flow and fund our operations through this just outstanding performance of these wells.

--------------------------------------------------------------------------------

Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [53]

--------------------------------------------------------------------------------

I appreciate that. And Gary, maybe I could just remind you, we've got our conference next week. That'd be a great time to start talking about this.

--------------------------------------------------------------------------------

Operator [54]

--------------------------------------------------------------------------------

Our next question comes from the line of Brad Heffern with RBC Capital Markets.

--------------------------------------------------------------------------------

Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [55]

--------------------------------------------------------------------------------

Just one for me. I was wondering if you could talk through just what you're seeing on the service cost front. I know you've been in sort of a unique position with some of the older long contracted rigs rolling off. But how are things looking right now especially in the context of the big move that we've seen in crude?

--------------------------------------------------------------------------------

Pat Bent, Continental Resources, Inc. - SVP of Drilling [56]

--------------------------------------------------------------------------------

Yes. This is Pat Bent. With respect to our rig contracts, we started the year with 18 rigs. We've had several roll-off contract to market rate, and that is generally a $10,000, plus/minus, per day reduction. We're currently with 18 rigs, we have 9 on market rate and 9 on long term. We'll have one more roll-off year-end to market rate, and so slight difference between Bakken and Mid-Con of a few thousand dollars, but in that $17,000 to $18,000 range market rate.

--------------------------------------------------------------------------------

Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [57]

--------------------------------------------------------------------------------

And then on the completion side, we've done a very good job this year just managing to the changing prices. And it's very much driven by supply and demand, and there's really still a lot of stim fleets that are available out there. I think about the Weatherford stim fleets that shut down earlier in the year and should be coming back on the market through the combined business venture called OneStim. And so I'm really looking forward to additional fleets being put to use. That ought to help our costs stay down.

--------------------------------------------------------------------------------

Operator [58]

--------------------------------------------------------------------------------

Our next question comes from the line of Leo Mariani with National Alliance Securities.

--------------------------------------------------------------------------------

Leo Paul Mariani, National Alliance Securities, LLC, Research Division - Research Analyst [59]

--------------------------------------------------------------------------------

Just a real quick question here on fourth quarter. Obviously, just very strong growth here from a number of fronts. Just trying to get a sense of what's driving that, if it's kind of all of your different key producing areas or if it's primarily Bakken. Certainly, one thing I noticed was that your SCOOP production kind of have been falling for the last handful of quarters. Is that expected to turn around in the fourth quarter? Maybe just kind of give us some thoughts on kind of what the moving pieces are by area that's kind of driving fourth quarter here.

--------------------------------------------------------------------------------

Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [60]

--------------------------------------------------------------------------------

I can -- this is Gary Gould. I can address some of that. Really, across-the-board, this has been just a record quarter for us. So if you think about production results in all our plays, we've talked about the Bakken, as you've mentioned, and this quarter, I believe our average type (inaudible) a record there, about 1,750 BOE per day for 57 wells we brought on. And then we've talked about our record well in the STACK condensate play. That's a new type curve area that came -- we came out with just last quarter and has an 80% rate of return on that type curve. And we haven't even added the Tres C well and the Lorene well into that type curve since we generated it. So that's an area that generates a high rate of return for us. Then in addition to that, we've got our STACK oil play where we've got our density tests, such as the Ludwig and the Compton. They are doing well and playing very strong. And then the Springer that Jack just talked about in how its production is 70% higher. So really, it's been a phenomenal year for us as far as just being more efficient with our CapEx and our LOE and increasing our rates of return and our plays across the company. The bottom line is if you're looking at kind of quarterly numbers as far as what STACK is doing from one quarter to another or what SCOOP is doing from one quarter to another, that's just depends on our -- to pad timing as far as when some of our large pads come on. And so I think that may address your question.

--------------------------------------------------------------------------------

Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [61]

--------------------------------------------------------------------------------

I think the biggest thing -- variable there probably was the length of time drilling complete the Sympson pad -- pads and unit. And of course, now if you look back, I mean, there's tremendous production coming from that.

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [62]

--------------------------------------------------------------------------------

Yes. I think the Sympsons will change the trajectory of the production there in SCOOP.

--------------------------------------------------------------------------------

Leo Paul Mariani, National Alliance Securities, LLC, Research Division - Research Analyst [63]

--------------------------------------------------------------------------------

Okay. That's helpful, for sure. I think on the previous call, you guys talked about 60% to 65% oil cuts, as a percentage of your overall production, being the goal here. Is that something you guys still plan -- you think you can get to here as we work our way into 2018?

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [64]

--------------------------------------------------------------------------------

I think we hit -- for the first half of September, we averaged 60% and that's before the weather hit up in the Bakken. And as we noted in the call, October was roughly at 59%. So yes, I think we can certainly achieve those targets. And we have a lot of optionality with really core assets that are continuing to improve, not only what you're seeing in the Bakken, but we updated you on the Springer results and how they're outperforming the type curves. So we certainly have that ability, and we've got the teams that can execute on those assets.

--------------------------------------------------------------------------------

Jack H. Stark, Continental Resources, Inc. - President [65]

--------------------------------------------------------------------------------

Yes Leo, we -- I mean, we clearly have the assets to drive that. It's just where we choose to (inaudible) rigs, and we're -- there's a lot of moving pieces and -- that influence where we put rigs. And so -- but to give you some color and some perspective on the capacity or capabilities we have.

--------------------------------------------------------------------------------

Gary E. Gould, Continental Resources, Inc. - SVP of Production & Resource Development [66]

--------------------------------------------------------------------------------

And we all -- this is Gary Gould. I'd add one more thing. If you look at our Slide 12, you can see what we've done with Bakken production. Just from January to August, we've grown production 35% in that play. And we've got additional DUCs that's going to grow that oil production in the Bakken some more as we go into next year. And then as Harold and Jack had mentioned earlier, we've also got the Springer play that will bring on a lot of oil production as we invest next year. So lots of oil potential, lots of optionality.

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [67]

--------------------------------------------------------------------------------

That Compton pad's a great example of what we can do with our oil ratio. I know last quarter, there was some that just didn't believe we could grow the oil volumes the way we said we would and could. And frankly, we've done it, and we're continuing to focus on liquids and [black oil].

--------------------------------------------------------------------------------

Leo Paul Mariani, National Alliance Securities, LLC, Research Division - Research Analyst [68]

--------------------------------------------------------------------------------

Yes. That's helpful, guys. I guess just last question here for you. On the STACK, just kind of looking at the wells on your slide deck here. Still noticing that you guys are drilling off a pretty broad area, and while your results are obviously very strong, there's still quite a bit of variability, particularly in some of these 24 IP -- 24-hour IPs. We've got wells that are over 6,000 and some that are closer to that, 1,500, 2,000 range. Can you guys maybe just talk about some of the variability here? I mean, what do you think is driving this? Is it just maybe sweet spots in the play or completion methods? Maybe just any color around some of the variability on the wide range of production results.

--------------------------------------------------------------------------------

Jack H. Stark, Continental Resources, Inc. - President [69]

--------------------------------------------------------------------------------

I would say a big driver is obviously geology in here. But even if you take a low-range wells and these IPs, they're still delivering very nice rates of return. So it's a question that you have is are they all going to be Lorenes? Well, we thought the Tres C was pretty respectable well and the question was could we repeat that. And by gosh, we did with the Lorene. And so I think that you have to -- you got to expect there's going to be variability because of the geology. There are variations in geology in here. We've seen remarkable repeatability here. But the variations you're talking about, to me, Leo, are more on the high end than on the low end. And so we do see some that are just exceptional wells out here, I mean, the biggest wells we've been involved with in our careers. I mean, I saw one write-up that said that -- I think it was Brian actually, that said that the Lorene is like a Permian well and a Marcellus well combined. I thought that was pretty interesting perspective because it came on for such high rates. And so -- anyway, so I think that I've said that I've -- this play is probably given the best repeatability of any resource play I've been involved with this early in the game. And I still stand behind that because it is -- the results are really pretty darn good, and we see a good repeatability. Now within a unit, you'll see performance that matches the unit. Like some areas just aren't quite as strong, but -- and the subsequent wells, we'll match that. But that ties more to geology. We are obviously making some headway testing different stims and what have you, and clearly, we'll be able to tweak that and improve that as we go.

--------------------------------------------------------------------------------

Operator [70]

--------------------------------------------------------------------------------

Our next question comes from the line of Derrick Whitfield with Stifel Financial.

--------------------------------------------------------------------------------

Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD & Senior Analyst [71]

--------------------------------------------------------------------------------

Bigger picture on the Bakken. Could you comment on the macro factors that are improving your differentials and to what degree they could further improve in the outer years?

--------------------------------------------------------------------------------

Unidentified Company Representative, [72]

--------------------------------------------------------------------------------

Some of the things that are happening, and we're having a lot of pipeline capacity that has really helped us to be able to do that. Additionally, the issues with the Canadian Syncrude with the outage in that Mildred plant has really helped us. So it's been a combination of those factors.

--------------------------------------------------------------------------------

Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD & Senior Analyst [73]

--------------------------------------------------------------------------------

And then if you think forward, any perspective on how that could further improve?

--------------------------------------------------------------------------------

Unidentified Company Representative, [74]

--------------------------------------------------------------------------------

Yes. I think we're seeing some growing appetite for Bakken crude, and I think we'll continue to see some attractive transportations.

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [75]

--------------------------------------------------------------------------------

We've got some legacy agreements that will be expiring and transitioning to more market norms now. It's a very positive trajectory. We've been talking about that trajectory for over a year now, and you're seeing the benefits of it. And that's why we also gave you some guidance on what we expect in the fourth quarter.

--------------------------------------------------------------------------------

Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD & Senior Analyst [76]

--------------------------------------------------------------------------------

Got it. If I could follow up on the Bakken type curve with my last question. It certainly appears that performance is strengthening in the outer part of the curve on Page 11. Is it fair to assume that some of that is driven by increased stimulated rock volume and, therefore, shallower decline and not just well count in the outer months?

--------------------------------------------------------------------------------

Unidentified Company Representative, [77]

--------------------------------------------------------------------------------

In the outer months, that's part of it. And part of it's what Jack referred to earlier too as far as it's a different well count. So it's not a -- that's -- it's a different well count as you go across that in days. But overall, it's very good performance. This type curve was developed even before we went to the testing for the 60 stages, and so there may be some additional benefit that we see from the 60 stages to even add to this type curve as we move forward.

--------------------------------------------------------------------------------

Jack H. Stark, Continental Resources, Inc. - President [78]

--------------------------------------------------------------------------------

Derrick, the fact that you see parent wells uplifted by the stimulation of the offsetting children wells tells you that we've just been under-stimulating these rocks over the years, and we're now just really getting better, I guess I'd say, stimulate the rock volume around the wellbores. And it's the best we've ever done with this -- with the technology we're using today, and it's -- you can see the benefits of connecting with more of that rock. And what we've seen in parent wells, which is interesting, you'll see -- obviously, the children wells outperform the parent wells, but we've seen the parent wells uplifted and their GOR will actually go down, which is proof positive that you brought additional new barrels or new -- connected with new reserves out there. So we -- this is a technological breakthrough, in my opinion, in the Bakken that's taken this whole field to another level.

--------------------------------------------------------------------------------

Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD & Senior Analyst [79]

--------------------------------------------------------------------------------

Yes, I definitely agree with your comments. I mean, the Bakken has been one of the best rate of change assets in the U.S. in 2017.

--------------------------------------------------------------------------------

Operator [80]

--------------------------------------------------------------------------------

Our next question comes from the line of Kashy Harrison with Piper Jaffray.

--------------------------------------------------------------------------------

Kashy Oladipo Harrison, Piper Jaffray Companies, Research Division - Research Analyst [81]

--------------------------------------------------------------------------------

As we look to 2018, could you just give us an idea of how much cash flow you would generate, assuming the $50 deck you alluded to earlier just based on your current expectation?

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [82]

--------------------------------------------------------------------------------

I would say it's very significant. But right now, we're working through a number of models. We don't want to put out bits and pieces. We'd like to put out everything in terms of the context. We still have board discussions and other things to go. So we're very pleased with the progress we're making, and I think you can see some significant positive cash flow and debt reductions. But we'll -- we're going to have to hold off until we come out with that early next year.

--------------------------------------------------------------------------------

Kashy Oladipo Harrison, Piper Jaffray Companies, Research Division - Research Analyst [83]

--------------------------------------------------------------------------------

Got it. That's helpful. And you highlighted your historical ROC, which was certainly one of the strongest in the industry over the course of the prior cycle. And so I was just wondering, could you give us a sense of how long it would take to get back to first double-digit ROCs, call it, 10%? And then how long it would take you to get back to the 20% objective, just assuming your -- just assuming current commodity prices?

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [84]

--------------------------------------------------------------------------------

I'll start with the end question. I guess our objective is to have as high of a ratio as we can. It's not necessarily 20% or this, it's to be as high as we can. During that 10-year cycle, we've had returns on capital in individual years upwards of 40% at different times. Last couple of years of 2 or 3 years with the lower commodity price, they've obviously been lower. But you've seen those in kind of a positive range certainly this year and flattish to positive in the couple of years before that. And it's growing significantly. It's improving significantly in '18. Part of that depends on what you see in terms of commodity price and everything. I don't think the objective of double digits is a long-term thing. You can certainly see that potentially as early as next year. It's coming -- it is coming with what we've done from an efficiency capital perspective, coupled with some improvement in commodity price thing. That's our objective, to get it as strong as possible.

--------------------------------------------------------------------------------

Kashy Oladipo Harrison, Piper Jaffray Companies, Research Division - Research Analyst [85]

--------------------------------------------------------------------------------

That's impressive. And then just last one for me. Just another type curve question. So with the -- you talked about a potential Springer raise coming in the next several months. And so would the uplift be similar to the Bakken, where we get a dramatic uplift in early recoveries but a lighter uplift to total recoveries? Or do you think it would be more evenly spread across the life of the well?

--------------------------------------------------------------------------------

Unidentified Company Representative, [86]

--------------------------------------------------------------------------------

I think it's similar to what you said, because we're definitely seeing the incremental rate upfront. So that's really going to drive our rates of return up high. And then part of this is due to longer laterals. Part of it's due to the incremental completion, so there's incremental optimized completions. And so there's definitely an add from an EUR standpoint also. So it'll be a combination.

--------------------------------------------------------------------------------

Operator [87]

--------------------------------------------------------------------------------

Our next question comes from the line of Jamaal Dardar with TPH & Co.

--------------------------------------------------------------------------------

Jamaal Dejon Dardar, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Associate, Exploration and Production Research [88]

--------------------------------------------------------------------------------

Quick question. Just -- -- I remember last quarter, you all talked about a $1.4 billion to $1.6 billion maintenance CapEx to keep your exit rate flat. Just kind of wanted to get updated thoughts there, understand that your new exit rate is a bit higher, but just want to see if that was still applicable next year.

--------------------------------------------------------------------------------

John D. Hart, Continental Resources, Inc. - Senior VP, CFO & Treasurer [89]

--------------------------------------------------------------------------------

Good question. Last quarter, we said $1.4 billion to $1.6 billion would help us flat in excess of $270,000. Now we're guiding to 280,000 to 290,000. So I think that you might be at the top end of that range or slightly above it, but not much above it if you are. So I think it's probably -- the top end of that's probably a good indicative for you as you think about that in terms of maintenance capital and this year's exit rate. Very capital efficient. We're continuing to see the productivity uplift that we talked about. We're continuing to see our breakeven prices go lower. So we're in a very good position, and that gives us the ability to not only do that but to put in some incremental capital to set up for a little higher exit rate next year and carrying into '19, setting us up well there as well.

--------------------------------------------------------------------------------

Jamaal Dejon Dardar, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Associate, Exploration and Production Research [90]

--------------------------------------------------------------------------------

All right, makes sense. And then just kind of a nuance question. Given the backwardation in the curve next year, just kind of want to get a sense on your ability to accelerate those Bakken DUC completions maybe in the beginning of the year in order to take advantage of that DUC price strength.

--------------------------------------------------------------------------------

Harold G. Hamm, Continental Resources, Inc. - Executive Chairman & CEO [91]

--------------------------------------------------------------------------------

Well, first of all, I'm not sure if you can depend on that price curve where it is, where that'll be because it very well can go the other direction pretty quickly. And we're seeing kind of a (inaudible) change in pricing occurring just over the last 2, 2.5 weeks. So I don't think we would project our work just on that. I think we see more of the fundamental happening with supply and demand balance that's taking place that will move prices to a higher level during the year.

--------------------------------------------------------------------------------

Operator [92]

--------------------------------------------------------------------------------

Our next question comes from the line of Eli Kantor with DIR Advisors.

--------------------------------------------------------------------------------

Eli Kantor, [93]

--------------------------------------------------------------------------------

Want to quickly revisit the success that you had in the Meramec downspacing initiative. Do you still plan on drilling completing the 4 Woodford wells that were part of the original design for the Compton downspacing pilot? And can you comment on how you think about co-development of those horizons going forward?

--------------------------------------------------------------------------------

Jack H. Stark, Continental Resources, Inc. - President [94]

--------------------------------------------------------------------------------

Yes. Ultimately, we see the Woodford being included in the development of these units. Right now, we wanted to accelerate our learnings by not including it. It'd just take that much more time, plus we wanted to have clear -- basically, a clear indication that this production and what we're doing was specific to the Meramec so we could really assess it. So longer term, you can see it and expect that it will ultimately be part of (inaudible).

--------------------------------------------------------------------------------

Operator [95]

--------------------------------------------------------------------------------

I'm showing no further questions in queue at this time. I'd like to turn the call back to Mr. Henry for any closing remarks.

--------------------------------------------------------------------------------

J. Warren Henry, Continental Resources, Inc. - VP of IR & Research [96]

--------------------------------------------------------------------------------

I'd like to thank everyone again for joining us on the call today. If you have additional questions, please give Alyson or me a call as always.

But in summary, we look forward to another exceptional quarter ahead and talking to you about our continued achievements in the fourth quarter.

With that, have a great day, and we'll sign off.

--------------------------------------------------------------------------------

Operator [97]

--------------------------------------------------------------------------------

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program. You may now disconnect. Everyone, have a great day.