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Edited Transcript of CLR earnings conference call or presentation 23-Feb-17 5:00pm GMT

Thomson Reuters StreetEvents

Q4 2016 Continental Resources Inc Earnings Call

ENID Feb 23, 2017 (Thomson StreetEvents) -- Edited Transcript of Continental Resources Inc earnings conference call or presentation Thursday, February 23, 2017 at 5:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Warren Henry

Continental Resources, Inc. - VP of IR

* Harold Hamm

Continental Resources, Inc. - Chairman and CEO

* Jack Stark

Continental Resources, Inc. - President and COO

* John Hart

Continental Resources, Inc. - SVP, CFO and Treasurer

* Glen Brown

Continental Resources, Inc. - SVP of Exploration

* Gary Gould

Continental Resources, Inc. - SVP of Operations

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Conference Call Participants

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* Brian Singer

Goldman Sachs - Analyst

* Clay Augumini

BofA Merrill Lynch - Analyst

* Brian Corales

Scotia Howard Weil - Analyst

* Edward Westlake

Credit Suisse - Analyst

* Steve Berman

Canaccord Genuity - Analyst

* Neal Dingmann

SunTrust Robinson Humphrey - Analyst

* Arun Jayaram

JPMorgan - Analyst

* Pearce Hammond

Simmons & Company International - Analyst

* John Freeman

Raymond James - Analyst

* Marshall Carver

Heikkinen Energy Advisors - Analyst

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Presentation

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Operator [1]

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Good day, ladies and gentlemen, and welcome to the Continental Resources, Inc. fourth-quarter 2016 earnings conference call.

(Operator Instructions)

As a reminder, today's program is being recorded. I would now like to introduce your host for today's program, Warren Henry, Vice President of Investor Relations.

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

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Thank you, Jonathan, and thanks to everyone for joining us this morning. I would like to welcome you to today's earnings call. Continental will start today with remarks from Harold Hamm, Chairman and Chief Executive Officer; Jack Stark, President and Chief Operating Officer; and John Hart, Senior Vice President, Chief Financial Officer, and Treasurer. Also on the call and available for Q&A later will be other senior members of the executive management team including Jeff Hume, Vice Chairman of Strategic Growth Initiatives; Pat Bent, Senior VP, Drilling; Glen Brown, SVP, Exploration; Gary Gould, SVP Production and Resource Development; Ramiro Rangel, SVP Marketing; and Steve Owen, SVP of Land.

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 SEC 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 this call, we will refer to initial production levels for new wells which in most cases are maximum 24 hour initial test rates. Finally, on the call we will refer to certain non-GAAP financial measures. For 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 the preliminaries covered, I'll turn the call over to Mr. Hamm. Harold?

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Harold Hamm, Continental Resources, Inc. - Chairman and CEO [3]

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Thank you, Warren, and good morning to everyone. I'm very proud of Continental's accomplishments in 2016. The Company performed at an excellent level in a second year of volatile commodity markets. Now we are pleased to be transitioning into stronger commodity markets that are reflective of supply and demand rebalancing.

We accomplished virtually all of our key strategic objectives for 2016, balancing capital expenditures with cash flow, and making good structural operating improvements. Although Continental has always been cognizant of its cost, we did reduce operating costs further throughout this year, and in the process, we recalibrated our Company's operations and raised overall performance to a very high level of efficiency.

Another important accomplishment. We increased the value of all of our plays. At STACK, we demonstrated the overpressured window as yet another cornerstone asset, and established STACK as a proven growth catalyst for our Company. STACK could add as much as 35% to Continental's unrisked resource potential.

Let's go back to this time a year ago, when we were only six months into the process of delineating the STACK overpressured window. In August of 2015, we announced the Ludwig parent well, our first well in the Meramec oil window. Then in early 2016, the market began to understand our excitement around STACK, as we announced the Boden 115-10 XH well, our first test of the overpressured condensate window. The Boden IPed at more than 3,500 BOE per day, with 1,000 barrels of oil per day.

I want to remind you, conventional wisdom at that time expected Boden to be a dry gas well. Then throughout the remainder of 2016, we continued to derisk our leasehold, focusing mainly on the overpressured oil window. Once again, our exploration success is clear and striking.

Today, STACK is firmly established as one of the premier onshore US resource plays, and Continental is now in density development, which should drive liquids-rich production growth in 2017 and 2018. A huge factor in all of our plays, of course, was the continuing advances made through 2016 in enhanced completion designs. As noticed in yesterday's release, advancement in completion technology enabled Continental to set new Company well production records in all of our plays, STACK, SCOOP, and Bakken.

From an investors perspective, of course the improved well results have significantly increased the value of all of our assets. This improvement from enhanced completions is also a key driver in our outlook for strong cash flow growth in 2017 and beyond. Another highlight of the past year was our activity in the North Dakota Bakken, where we built a large high-value backlog of uncompleted wells, and wells that were completed but not yet in production at year-end. Working down this inventory will benefit production and cash flow growth in 2017 and 2018.

This year-end inventory of 187 gross wells represents our most capital efficient opportunity to drive oil concentrated production growth for the Company. We have rapidly accelerated the deployment of completion crews to realize that opportunity. You should expect a steady stream of news on these Bakken activities throughout the upcoming year.

Finally, as we increased the value of our leasehold assets this past year, we also strengthened our balance sheet. We monetized certain non-strategic assets, used the proceeds to reduce debt by more than $600 million from its peak, and kept our capital spending on a balance with cash. Our strategic, our strategy remains disciplined spending and as balance sheet management to deliver fully -- full value to our shareholders.

Today, the significance of 2016 and its achievements of course is how it sets the stage for stronger production and cash generation ahead. Looking to 2017, we plan to remain focused on oil concentrated growth, and strong investment returns, as oil prices stabilize at higher levels.

As we announced in late January, we expect multi-year production growth of at least 20% on a cash-neutral basis. As I said last month, I've never been as enthusiastic and positive about a prospect for the Company. And given that 2017 marks our 50th year in business, there couldn't be a better time to celebrate the opportunities ahead.

So another solid year is in the books, and we're preparing to achieve even stronger results in the New Year. With that overview, I'll turn the call over to Jack Stark.

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

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Thanks, Harold, and good morning, everyone. We appreciate you joining us on our call today, and as Harold pointed out, the broad range of achievements made by our employees in 2016, combined with the quality of our assets, really sets the stage for 2017 performance and beyond.

The net result is that today we are funding twice the reserves per dollar spent than we did in 2014, and our operating costs are among the lowest in the industry. And due to the structural nature of these achievements and the depth of our inventory, we believe Continental will continue to deliver these industry-leading results for many years to come. Now today, I will highlight some of our fourth-quarter results and continue to validate these achievements, and provide some color on our operational plans for 2017.

So let's look at some of the fourth-quarter highlights. I'll begin with STACK, where we continued to achieve excellent results from our Meramec drilling. In all, we completed another seven operated Meramec wells in the overpressured oil window, with initial rates ranging from 1,600 BOE per day to 2,500 BOE per day, and full encasing pressures up to 3,900 PSI, and oil cuts ranging from 55% to 73%.

We continue to be impressed with the overall repeatability demonstrated by these new wells, and the sustained performance from our previous Meramec completions that continue to support our 1.7 million BOE per well type curve. For reference, updated production data for our Meramec wells with over 100 days of production is provided on slide 16, in a presentation on our website.

To date, we have derisked approximately 47,000 net acres in the overpressured oil window, and this area contains 55 operating units ready for development. And the impact that these 55 units can have on our production growth is quite significant. For reference, our Ludwig unit announced last quarter had a combined initial 24 hour flow rate of 21,400 BOE per day from eight wells, with 70% being oil.

Ludwig was the first fully developed multi-zone Meramec unit in the overpressured oil window, and included four wells in the upper Meramec, and four wells in the middle Meramec. The unit has already produced 1.75 million BOE from these wells. With impressive performance like this, it's clear STACK has quickly become a key catalyst for Continental's growth, and a great addition to our world-class portfolio of assets.

We currently have four rigs focused on developing these 55 units, targeting up to three different Meramec zones, and testing up to six wells per zone. We expect to complete at least 40 Meramec wells and six of these units by year-end 2017.

In our release, we also announced the long awaited results from our prolific Anderson Half well, in what we are calling Deep STACK. Along with the Anderson Half, we also announced results from two equally prolific confirmation wells, the Edith Mae and Eichelberger, which are located one mile west and two miles east of the Anderson Half. Bottom line, we couldn't be more pleased.

All three wells flowed in excess of 20 million cubic feet of gas per day from the Meramec, at pressures raging from 5,500 to 7,500 PSI from their 9,700-foot laterals. These are exceptional gas wells and clearly could be produced at higher rates. We currently estimate these Meramec wells to recover in excess of 20 Bcf each, and deliver a 50% rate of return at $3.50 per Mcf gas, and a completed well cost of $11 million.

The performance of these three wells once again demonstrates the tremendous resource we have underlying our acreage in STACK. Deep STACK is another significant discovery for Continental, and we'll provide more details in the future.

Before moving on to other plays, I thought I would provide just a quick recap of the six key achievements we made in STACK during 2016: First, we established prolific production from all three hydrocarbon windows, oil, condensate, and gas. Second, we demonstrated repeatable performance from three different Meramec zones underlying our acreage.

Third, we completed the first fully-developed multi-zone Meramec density pilot, with outstanding results. Fourth, we demonstrated that we can expect up to 30% reduction in drill costs and 36% reduction in drill days when moving to density development.

Fifth, we added another 45,000 net acres of leasehold, bringing our acreage in the play to slightly over 200,000 net acres. And sixth, we derisked 47,000 net acres in the overpressured oil window, and began development.

Now, current drilling results indicate that 40% of our 200,000 net acres in STACK are located in the oil window, 30% in the condensate window, and 30% in the gas window. And so as Harold said earlier, with the outstanding results we've experienced to date, we believe STACK can add up to 35% to our net unrisked resource potential for the Company.

Now let's move to another highlight from our fourth quarter, enhanced completions, which continue to uplift production rates, estimated recoveries, and economics in all of our plays. In the Bakken, we have seen 90 day production uplifts of 35% on average over our 980 MBOE type curve from seven recent wells. These wells were completed using various enhanced stimulation techniques, and more aggressive flowbacks.

Three of the seven wells delivered Company-record 30 day rates. This is great news, and great timing, as it allows us to reap the benefits of these techniques, while completing our year-end 2016 inventory of 187 Bakken wells. The completion costs for these enhanced stimulations is approximately $4.9 million per well, and the cost forward returns are in excess of 100% at $55 WTI.

In SCOOP, we've also seen performance uplifts in both the oil and condensate windows from these enhanced stimulations. In the SCOOP condensate window, we increased EURs by another 15% to 2.3 million BOE or a 7,500-foot well, based on the continued improved performance of 26 enhanced completed wells. At an average expected cost of $10.3 million per well, SCOOP condensate wells deliver an impressive 80% rate of return, assuming $55 WTI and $3.50 gas.

A couple of recent completions in the condensate window include the Boatright and Peppered Ranch wells. The Boatright flowed an impressive 3,460 BOE per day at 3,160 PSI, performing a 10,000-foot lateral, with 29% being oil. The Peppered Ranch flowed at an equally impressive rate of 3,550 BOE per day at 3,220 PSI, from an 8,600-foot lateral, with 26% being oil. And the gas in this area is liquids rich at 1,270 BTU.

From the SCOOP oil window, we recently completed the Emery, which flowed 1,330 BOE per day at 500 PSI pressure from a 9,700-foot lateral, and 77% of the production was oil. The Emery was completed with tighter stage basing, and more proppant per foot than its offsets.

Now before I turn the call over to John, I want to provide a couple highlights on our 2017 budget. First, our 2017 drilling and completion program is oil weighted. Approximately 82% of the capital is allocated to Bakken and STACK, which deliver a production stream that combined is approximately 75% oil. This does not include associated NGLs that theoretically could add another 10% to the total liquids, if we were a three stream reporter like many of our peers.

Second, the budget only includes one additional drilling rig. However, our completion group count in 2017 increases significantly. In the Bakken, we are already operating five crews, and expect to add three more crews by May.

These crews are expected to harvest 148 Bakken wells in 2017, and they will also complete an additional 72 Bakken wells that will be waiting on first production at year-end 2017, providing continued momentum to our production growth in 2018. In SCOOP and STACK, we currently have three stim crews running, and expect that to rise to five by the end of March.

And third point is that we have modeled in a 5% to 10% increase in costs by year-end 2017. This may be lower than others in the industry, but this is a blended estimate that includes service cost increases that are partially offset by continued efficiency gains that we expect, and lower drilling costs, as term rig contracts expire during the year.

As announced in our press release, we have resumed operations in the SCOOP Springer play, and in 2017 we plan to drill and complete at least five Springer wells to evaluate the benefits of extended laterals and the latest stimulation technologies. We're anxious to see the improvements that these technologies will deliver, and we use the results to optimize our development plans for this oil rich play.

We also plan to test additional zones underlying our STACK and SCOOP acreage in 2017. STACK and SCOOP, as you know, are part of the world-class Woodford Petroleum System that ranges from hundreds to even thousands of feet that contains multiple hydrocarbon charged reservoirs. Like the Springer and SCOOP, these reservoirs can add significant resource potential to the Company, at little to no additional acreage cost.

This activity is just one of the many potential catalysts for Continental in 2017, so stay tuned. With that, I'll turn the call over to John.

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John Hart, Continental Resources, Inc. - SVP, CFO and Treasurer [5]

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Thank you, Jack. Good morning, everyone. As Harold and Jack pointed out, we had a great finish to 2016, setting the stage for 2017. Let me start with year-end results that showcase how 2016 reflected our continued focus on cost and efficiency.

Revenue for the fourth quarter was $520 million. Net cash provided by operating activities was $262 million, and EBITDAX was $652 million.

Net income for the fourth quarter was $27.7 million or $0.07 per diluted share. Adjusted to exclude impairments, non-cash gains and losses on derivatives, gains and losses on asset sales, and losses on extinguishment of debt, we posted a net loss of $27.4 million, or $0.07 per diluted share for the fourth quarter.

Revenue for the full year was $1.98 billion. Net cash provided by operating activities was $1.13 billion, and EBITDAX was $1.88 billion.

Continental reported a net loss of approximately $400 million or $1.08 per diluted share for the full year. Adjusted for items noted previously, the annual adjusted net loss was $327 million or $0.88 per diluted share.

Full-year production came in at approximately 217,000 BOE per day. Production averaged 210,000 BOE per day in the fourth quarter, increasing from the third-quarter average, but reflecting severe weather, primarily in the Bakken during December. Production in February has recovered to approximately 215,000 BOE per day, as the weather has improved.

Oil production was 59% of total production for the full year, and 55% for the fourth quarter. The oil percentage of total production is expected to rise throughout 2017, and we expect to rise to approximately 60% later in 2017, as we bring Bakken pads online.

During the quarter, we divested certain non-core largely non-operated assets in SCOOP for $296 million, and recognized a gain on this transaction of $201 million. Proceeds of this divestiture were applied to debt reduction, as we will discuss in a moment.

Non-acquisition capital expenditures for the fourth quarter were $306 million, bringing full-year non-acquisition CapEx to $1.07 billion, just under budget. These expenditures were funded by our operations, while we further reduced debt with asset divestitures. Operating cost performance continued to be very strong throughout the year, with absolute costs lower in the second half of the year, as compared to the first half by 16 million.

Production expense dropped to $3.60 per BOE in the fourth quarter. Full-year production expense averaged 3.65 per BOE down 15%, compared to $4.30 per BOE for the full year of 2015. Our guidance for 2017 is $3.50 to $4 per BOE, as we expect to increase Bakken production, where production expense runs approximately $4.50 per BOE, while SCOOP and STACK are each typically below $2 of BOE.

Fourth-quarter G&A excluding equity compensation was $2.21 per BOE. Non-cash equity compensation was $0.72 per BOE of production, for total G&A of $2.93. Full-year cash G&A was $1.53 per BOE, and full-year non-cash equity compensation was $0.61 per BOE, or a total G&A of $2.14. Each are well within our guidance.

G&A for the fourth quarter was elevated due to year-end compensation adjustments, thus the fourth quarter G&A rate is not indicative of what we anticipate in 2017. For the full year 2017, we expect G&A, excluding equity compensation, to range between $1.50 and $2 per BOE, and between $2.10 and $2.70 per BOE, if you include equity compensation. Select cash costs, including lease operating expense, production tax, cash G&A, and interest expense, were lower at $11.01 per BOE for the full year, down an impressive 11% from full-year 2015, even with slightly lower production year over year.

As we head into 2017, we expect to remain an industry leader in operating cost efficiency. As expected, our oil differential has continued to improve, with approximately 90% of our Bakken production now delivered to market via pipeline. The full Company fourth-quarter oil differential was $6.95 per barrel, while the full year was $7.33, both within guidance.

As noted in prior quarters, and reflected in 2017 guidance, we believe improvement in oil differentials will continue, as additional pipeline capacity becomes available in the Bakken, and as SCOOP and STACK contribute an increased share of total Company production.

The fourth-quarter gas differential was a negative $0.28 per Mcf, while full-year 2016 averaged a negative $0.61 per Mcf. Improving gas differentials were attributable to improving liquid prices.

Now, I'd like to discuss our 2017 outlook in greater detail. For 2017, our capital budget of $1.95 billion is focused on spending within cash flow. This budget is cash neutral at an average WTI price of $55 for the year.

The strip is closely approximating this price now, and we are in good shape. As a reference point, a move in WTI prices by $5 will impact our full-year cash flow by approximately $200 million. The budget provides strong production growth in the back half of the year, targeting a 2017 exit rate between 250,000 and 260,000 BOE per day, up 19% to 24% over the fourth quarter of 2016.

For the first half of 2017, we expect production to range between 210,000 and 215,000 per day. During the first quarter, we are likely around the midpoint of this range, due to severe weather in the Bakken impacting January production. The good news is that production has quickly recovered to approximately 215,000 BOE per day in February, and we now expect the second quarter to be towards the top end of our first-half range or even higher.

As we enter the second half of 2017, we expect to see significant production growth as pad completions come on line, growing into our expected exit rate of 250,000 to 260,000 per day. We expect to end 2017 with approximately 140 uncompleted Bakken wells in inventory, with 72 of those already completed and waiting on first sales, and the other 68 wells scheduled for completion in 2018.

Wells in inventory are net of working down our uncompleted well inventory, while also adding new wells from drilling. The key take away is that the capital we spend in 2017 not only benefits the current year, but will be a catalyst for multi-year growth. We are set up extremely well for strong growth in 2018, on a cash-neutral basis, I might add.

Therefore looking beyond 2017, we project significant annual production growth over the next five years. With our current inventory, we should be able to grow production 20% annually and remain cash neutral at a price in a band of $60 to $65 per barrel WTI. Now of significance, we could remain cash neutral in the out years at lower oil prices, depending on how we choose to deploy capital.

Our current model actually shows us generating excess cash between $60 and $65, allowing us to deploy additional capital to operations or debt reduction, both of which are positive to the Company valuation and results. With that being said, we are choosing to remain conservative from our outlook beyond 2017, as there is potential market uncertainty among many other factors that are hard to predict and could impact cash flow, production, and commodity price estimates.

Additionally, we would note that the depth and quality of our inventory sets the stage for significant growth and value capture, not only for the next five years, but also well after there. We plan to provide updates to 2018 and beyond throughout the year.

Another focus is getting back to investment grade with the rating agencies. We continue to remain in regular communication with both agencies, and feel confident that we can get our ratings increased to investment grade. Further, we may engage with additional agencies in 2017.

One way to aid the process is for us to get to our long term debt target of $6 billion or below. We do not intend to sacrifice production growth to achieve this, but instead, we will look to monetize additional non-strategic assets, and apply excess cash to debt. These efforts are ongoing, and we will update you in the future.

Our debt position improved throughout 2016, as we reduced outstanding debt by $538 million, as compared to year-end 2015. Most recently, we closed on the redemption of $600 million of our 2020 and 2021 Senior Notes, saving the Company in excess of $40 million in annual interest payments. Our debt at the end of 2016 was $6.58 billion.

As of January 31, total debt had decreased by another $65 million, improving to $6.51 billion. So that puts debt reduction at $603 million relative to year-end 2015, or almost $700 million if you compared our peak level of debt of $7.2 billion in May 2016.

I will close by commenting on all that we achieved in the past year. We were able to finish out the year within all of our guidance measure ranges, even after positively updating guidance several times over the course of the year.

We also made hefty strides operationally through the use of enhanced completions in all of our plays, while also shifting to density drilling in the STACK overpressured oil window. In Bakken in late 2016, we begin working down our large inventory of uncompleted wells, which will aid 2017 and 2018 strong production growth.

With that, we're ready to begin the Q&A section of our call. Operator, we'll turn it back over to you now.

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Questions and Answers

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Operator [1]

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(Operator Instructions)

Our first question comes from the line of Brian Singer from Goldman Sachs.

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Brian Singer, Goldman Sachs - Analyst [2]

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Can you talk about the various drivers of moving the oil percentage from 58% to the 60% to 65% guidance longer term, particularly given that the STACK wells can get a bit gassier over time? And specifically how significant to ramp should we expect in Bakken drilling, once the ducks are completed, and how strategic is your acreage in STACK gas window once that area is delineated?

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Harold Hamm, Continental Resources, Inc. - Chairman and CEO [3]

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If I missed some of that feel free to come back again. If you look back to the back half of 2015, and certainly through the bulk of 2016, we weren't completing all the wells in the Bakken that were 85% black oil. So as we're bringing those back on with the large level of completion activity we have not only in 2017 but those that are completed, but with first production in 2018 you're going to see a strong growth in the oil percentage coming out of the Bakken. With the additional takeaway capacity and the differentials improving, I think our time is going to prove to be very fortuitous from that regard.

Additionally, with what you've seen in STACK we've shifted to where we are continuing to delineate the play, but as you may be aware, the bulk of our activity in terms of drilling is in that Ludwig density area. It's the dotted line on our chart in the investor slide deck. That's an oil heavy area. We've seen very encouraging results from that over the last year and a half, that's going to grow oil.

And then further we're moving back into the Springer, as we noted in the release, and that's 80%-plus oil there also, so our focus is bringing oil back on, in what we see to be a better market certainly than it was a year ago, and with the efficiencies and the quality of the wells that we've garnered we've got a tremendous results. So that's a multi-year growth, and that's why we've tried to give you that color and transparency going out into the future.

Brian, you had a lot there. Can you give me your other aspects?

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Brian Singer, Goldman Sachs - Analyst [4]

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You got most of it. The last little piece of it was, you talked about very strong gas rates in the STACK overpressured gas window. Does that become less strategic or candidate for asset sale or that just gets worked into the weighted average?

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Jack Stark, Continental Resources, Inc. - President and COO [5]

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Brian, this is Jack. The Anderson Half well as you can see, was a very impressive and prolific well, and it was so good that we felt we needed to step back and see if we couldn't confirm those rates, and we did with the two offsets. So we're very comfortable that we have very significant gas asset there.

But we're comfortable now that we're going to be able to HBP that with the drilling we're doing underneath our Northwest Cana JDA that we've got with SK. And so we're probably not going to do a lot of drilling down there near term, outside of what we're doing through the JDA, and that's really effectively HBPing our acreage. So we really like the asset, and those rates are really impressive.

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Brian Singer, Goldman Sachs - Analyst [6]

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Thanks, and maybe one more on SCOOP and STACK. It seems like there's a theme of some conservatism among some of the producers regarding productivity gains in the area. Beyond delineating the right spacing, can you talk specifically about what you're focused on and the scope for further productivity improvements?

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Jack Stark, Continental Resources, Inc. - President and COO [7]

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As far as there's three of us stepping up to this I'll say the productivity improvements, these are the best wells we've ever drilled in our career, so productivity improvement, I'm really pleased with what we've got right now. But I do think that there's always upside to what we've been doing, and we are working and testing different stimulation techniques, and we're actually even testing, maybe we can back off on some of these stims and do as well.

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Harold Hamm, Continental Resources, Inc. - Chairman and CEO [8]

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As far as density disparity among operators, we've led the industry out there with the Ludwig, with full density drilling, and we've seen nothing that would back us off of the density that we're heading for.

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Glen Brown, Continental Resources, Inc. - SVP of Exploration [9]

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This is Glen Brown. I'd like to add that zip code matters. Where your acreage is and what you're talking about in STACK, they are, just reminding everybody that we have a shallow part and deep part of the play.

Our reservoirs are twice as thick as the normal pressured play. We have twice as much pressure in our overpressured area, and so therefore, you can get commentary from the other parts of the play in a different zip code that may not be consistent with where our play is.

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Brian Singer, Goldman Sachs - Analyst [10]

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Great, thanks so much for the color.

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Operator [11]

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Thank you. Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch.

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Clay Augumini, BofA Merrill Lynch - Analyst [12]

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This is Clay on for Doug. My first question is on the Bakken duck wedge. So you have previously guided to about 30,000 to 40,000 per day by year end, as the contribution from that duck inventory. Can you talk about what type curve is embedded into that assumption, whether that's different than the 980 type curve that characterizes your ducks? Basically what I'm trying to understand is whether there's upside to the scale of that contribution, based on latest guidance, and whether there could be even more upside based on the actual performance of the enhanced wells you guys are showing?

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Gary Gould, Continental Resources, Inc. - SVP of Operations [13]

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This is Gary Gould, and what we have baked into it is that 980 type curve for the ducks, and a 920 type curve for our newest drill wells that we're targeting this year. We're drilling a different part of the core, or where we are completing our wells, so that explains the difference between those two numbers. And so what you can see from our results is that we are very encouraged by the additional testing that we're doing.

We're doing additional testing with more proppant. We're doing additional testing with smaller stages, and we're continuing to use the newest diverter technology to help increase those improvements. So there's still room to grow as far as how we're optimizing our completions.

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Harold Hamm, Continental Resources, Inc. - Chairman and CEO [14]

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Clay, that wedge that we gave, the 30,000 to 40,000, that's based just on the ducks, and by the end of the year, we're pretty much moving away from that term duck. We're moving more back into wells in progress and getting back to a normal inventory by the end of the year, so it's a strong catalyst there. And as Gary said, the early time results on what we're seeing on some of these larger completions are certainly performing at a higher level, so that's something for us all to watch throughout the year, and we're excited about that opportunity.

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Clay Augumini, BofA Merrill Lynch - Analyst [15]

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Got you. How many of the 148 wells you're planning to bring on in the Bakken are going to feature those enhanced completions?

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Harold Hamm, Continental Resources, Inc. - Chairman and CEO [16]

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All of them.

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Clay Augumini, BofA Merrill Lynch - Analyst [17]

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Got you, okay. Second question is just on the STACK. You released a bunch of well results in the press release, and there seems to be some variability in the range of the production on an IP24 basis. Just trying to understand what's driving that. Specifically looking at the Winter Still well which provided the lowest rate, but also with an extend to lateral. So I'm guessing that lateral length doesn't seem to tell the whole story, so I'm wondering what's going on there.

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Glen Brown, Continental Resources, Inc. - SVP of Exploration [18]

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This is Glen Brown. Let me address the seven wells in general. We do have a mixture of different lateral lengths, more short one-mile wells in general, so let me just do some quick math for you. We have an average length of those seven wells at 7,628 feet, and if you normalize those to 10,000-foot laterals, we're looking at 2,768 BOE per day.

We have a 67% average oil and an average pressure at 3,200 pounds, so what I see out of that is on a normalized basis, consistent reservoir results. As far as an individual well here or there, there is always the geosteering anomaly. Occasionally we get in and out of the zone, and we're still crafting our trade there, and getting better on each and every well as we go forward.

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Clay Augumini, BofA Merrill Lynch - Analyst [19]

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Got you. Appreciate the comments guys.

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Operator [20]

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Thank you our next question comes from the line of Brian Corales from Howard Weil.

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Brian Corales, Scotia Howard Weil - Analyst [21]

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This is maybe more of a general question on the enhanced completions. Obviously the more proppant and diverters have worked up in the Bakken. Are you all still testing like the outer extent of more proppant and other things to even further enhance completions?

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Gary Gould, Continental Resources, Inc. - SVP of Operations [22]

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Yes, this is Gary Gould. Yes, we are. We are currently testing between 1,000 and 2,000 pounds per foot up in the Bakken. But I would also say we see a lot of other operators testing just really high amounts over 3,000 pounds per foot. And just looking at all our plays right now, I think optimum will be coming in somewhere between a 1,000 and 2,500 pounds per foot. Does that answer your question?

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Brian Corales, Scotia Howard Weil - Analyst [23]

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Yes, that's helpful. And then I would assume you're further along in the Bakken, and as you go to the STACK and probably now restart the Springer, are you all going to take similar type increases to these new plays, versus what you all have done in the Bakken?

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Gary Gould, Continental Resources, Inc. - SVP of Operations [24]

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Yes, we are. This year, in the Springer we've got five wells we're currently planning to drill, and will be testing both our enhanced completions and longer laterals in those wells.

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Brian Corales, Scotia Howard Weil - Analyst [25]

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Okay and one final one if I can, and John maybe for you. I know this was implied in one of the other questions, but it just seems like all of the wells in the plays keep getting better, versus what you all put out in guidance a couple weeks ago, versus the outlook for 2017 and 2018. I'm assuming it's not all baked in?

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John Hart, Continental Resources, Inc. - SVP, CFO and Treasurer [26]

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We've got a history of beating and raising our guidance as we go through. That's been based on the productivity that we've seen out of continuing to test technology. We're continuing to do that now. We're extremely pleased with the early time results we're seeing, so we'll monitor those throughout the year. But rest assured, we'll do everything in our power to optimize results.

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Brian Corales, Scotia Howard Weil - Analyst [27]

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All right, thank you and good job on the quarter.

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Operator [28]

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Our next question comes from the line of Edward Westlake from Credit Suisse.

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Edward Westlake, Credit Suisse - Analyst [29]

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Two questions. First one is again on the Bakken theme of the work that you have done, and the industry in improving completions. As you've done this, presumably there's also an inventory impact, in terms of your view of how many wells you can drill out there in the Bakken, maybe some color on that. How many wells you can drill at 920 or 980?

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Gary Gould, Continental Resources, Inc. - SVP of Operations [30]

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Well we've got 15 years at least that we could drill with 15 rigs, and we're at four rigs right now. So inventory is not an issue, and that's at an average 775 MBOE equivalent. I don't have a number for you that would be the average 980, but we've got a couple decades of inventory up there, and really delivering these results for the next five plus years is not a problem.

But what we can tell you is that when you think about what these enhanced stims are actually doing, they are uplifting obviously the performance of the wells in the core, but what it also is doing is expanding what you might define as the core. And you know, we had those step outs we drilled in Maryland and Nashville, and we moved way out, 40 miles west of down there in our Antelope area. So substantial uplifts there in those wells offsets. And so I think bottom line is, I think what is core today is continuing to expand.

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Edward Westlake, Credit Suisse - Analyst [31]

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That's what I was trying to get at. The other aspect is obviously proppant and sand availability. Maybe talk a little bit about your access to sand, if you have any concerns, how much capacity you've got locked up today? That may be a constraint as the whole industry gets back to work or not, and any comments on fine mesh versus coarse?

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Gary Gould, Continental Resources, Inc. - SVP of Operations [32]

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Gary Gould again, and we do many things that help us be prepared for our sand designs. First of all, we work with many different vendors in both the north and the south, and that way when we have multiple vendors, we can work with them to make sure we have good performance for sand deliveries, and every other part of performance associated with the completions.

Secondly, as I stated earlier, I see some of this very large testing going on. Our teams are continually testing what is optimum, so there's many different ways to get better results. It's not just more sand, sometimes it's smaller stage spacing, sometimes it's cluster spacing, use of the diverter.

So our teams are always looking at all of that, and again right now I think that optimum rate is not at the 3,000 or higher, I think it's going to be 2,000, 2,500 or below in pounds per foot. So I don't foresee a challenge associated with bringing sand to a location.

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Harold Hamm, Continental Resources, Inc. - Chairman and CEO [33]

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And we tapped it in some areas, in some formations lower sand volumes that seem to work better than more sand. It's not proved yet in the Bakken, but in some other plays that is.

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Glen Brown, Continental Resources, Inc. - SVP of Exploration [34]

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This is Glen Brown. I think part of your question was small mesh versus coarse?

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Edward Westlake, Credit Suisse - Analyst [35]

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Yes.

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Glen Brown, Continental Resources, Inc. - SVP of Exploration [36]

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We have done a considerable amount of testing with smaller mesh, and had very positive results there, as well, so they have an industry shift in that direction.

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Edward Westlake, Credit Suisse - Analyst [37]

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Okay, thank you very much.

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Operator [38]

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Our next question comes from the line of Steve Berman from Canaccord.

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Steve Berman, Canaccord Genuity - Analyst [39]

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Jack, I think I heard you talk about maybe testing some other formations in Oklahoma during the course of the year. Almost by process of elimination, I would say Sycamore comes to mind, and other companies throughout this earnings reporting season, without saying what they are, have talked about testing other formations beyond the Meramec, I guess in your case Meramec and Woodford. Can you elaborate and maybe talk a little more about what you might do there?

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Jack Stark, Continental Resources, Inc. - President and COO [40]

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Sure. Those are obviously two reservoirs that exist in this system that are very high potential, and yes, they would be included in a list of zones we would be testing, and we have other zones as well that we'll be testing. So you've got a very thick petroleum system here with multiple layers and reservoirs, and so through the year, you'll see us, we'll be doing some testing, and depending on the pace at which we can get those tests done, we'll share some of those results.

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Steve Berman, Canaccord Genuity - Analyst [41]

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And then second question, in the deep STACK, those are some really nice wells there. You talk about the economics at $3.50 gas, gas has sold off over the last few weeks or so. I'm just wondering how sensitive further activity in that program this year is, how sensitive that is to the gas price?

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Gary Gould, Continental Resources, Inc. - SVP of Operations [42]

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At $3, that rate of return is 35%, and at $2.50 gas, that rate of return is 22%.

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Harold Hamm, Continental Resources, Inc. - Chairman and CEO [43]

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We've mentioned, Steve that we have protected the Company with hedges.

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Steve Berman, Canaccord Genuity - Analyst [44]

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Excellent. Thank you, gentlemen.

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Glen Brown, Continental Resources, Inc. - SVP of Exploration [45]

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This is Glen Brown. I'll just add on there that those economics are for parent wells, and we have a history of proving our completion well cost as we move to pads, so those, there's upside for those rate of returns to improve. In the deep yet.

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Operator [46]

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

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [47]

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There is a follow-up to what somebody asked earlier. My question is really about how you look at Harold for your choke management program. Seems like a lot of us on Wall Street focus a lot on IP30s or 60s or even 24 hour, if you will, and I'm just wondering how you all look at it again, when you think about the choke management? Anything from the Ludwig all the way to what you all deem those deeper STACK tests?

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Harold Hamm, Continental Resources, Inc. - Chairman and CEO [48]

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I'll turn it over to Gary and let him, it is pretty complex. I'll let Gary run through it for you.

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Gary Gould, Continental Resources, Inc. - SVP of Operations [49]

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Sure, I'll talk about that. So if you think about last year, there were times where we had purposefully shut back gas production because of price, and also other times we shut back oil production because of price. And so last year there was a lot of times where we were not really in a position where we wanted to increase the rates through more aggressive choke management.

And so what we are doing this year, let's take the Bakken to begin with, is multiple things. We've got the enhanced completions that is working to increase the reserves and increase the rate, and then we've got two other mechanisms that are working to increase the rate at the beginning of the well's life.

First of those two is more aggressive choke management and then the second piece is higher rate production lift. And so we are employing both of those items in the Bakken this year, to increase our early production rates.

And then also in the STACK, you asked about. In the STACK, we manage the bottom hole pressure to stay above bubble point for as long as we can, and then at that point, we go ahead and produce the well. The great thing about being in the overpressured area is we've got such strong pressures that those pressures are able to continue to drive the volumes of fluids out, whether they be both oil or gas, and so we will continue to have great production rates from both fluids in every window, because of our overpressured nature of that reservoir.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [50]

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So Gary when I look at, let's just focus on like the deep STACK, where you've had the read add particularly, is that more concentrated in all-in managing that bottom hole pressure? Because again, it appears to me even if you all wanted to open that up, you could have had a much higher IP, had you chosen.

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Jack Stark, Continental Resources, Inc. - President and COO [51]

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So for the deep STACK, that's dry gas. So really that's just a matter of producing a rate we are capable of. I would tell you that we are very pleasantly surprised by our rates in the deep STACK, and we are facility restrained on those at about 20 million a day. So you're right, we could produce those at a higher rate, through just changes in our design, and that would improve our economics further.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [52]

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One last follow-up if I could. How do you look at, I'm looking at slide 14 on one of your last decks that shows the density test in the Meramec overpressure. So what I'm wondering if you look, starting to Ludwig and going west, if you could talk a little bit about thickness, and if you do have the potential there for upper, middle and lower, if you all assume for all three of Meramec zones in that area?

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Jack Stark, Continental Resources, Inc. - President and COO [53]

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I'll actually refer you to a slide I think we've got in the appendix here, page 29, and what it shows in the thickness of each of these units and the targeted intervals within the Meramec that we're going for. So that could probably give you some perspective on what we're doing here, but you could see it ranges anywhere from 675-foot thick total to about 785-foot thick and in each of these right now, we're looking in this particular area, we're targeting the upper and lower Meramec in these units. And you can also see we've got wells that ultimately would be targeted for the Woodford as well, and you can see also that we're looking at testing anywhere from -- we've got from three to four to five and even six wells that we'll be testing there in the Angus Trust per zone.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [54]

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Jack would the thickness, silly question, would the thickness the deep STACK, be about the same or would that be a bit thicker than this page 29?

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Jack Stark, Continental Resources, Inc. - President and COO [55]

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No, you get substantially thicker as you go down to the southwest. This particular system here we're showing about say 750 feet thick here, you go down there that area Glen is about 1,200 feet thick. So you can see it's not quite a double but pretty close.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [56]

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Got it.

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Jack Stark, Continental Resources, Inc. - President and COO [57]

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That's one of the big drivers there is you've got this extreme overpressure, you're looking at 0.8 PSI per foot pressure gradient, and on top, of that, you got almost double the thickness. So when Glen is saying the zip code matters and being in the right area where the reservoir is best developed, it definitely is critical, and as you move down to the South and West, we're getting thicker and even better quality.

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Neal Dingmann, SunTrust Robinson Humphrey - Analyst [58]

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Great, thanks much for the details.

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Operator [59]

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Our next question comes from the line of Arun Jayaram from JPMorgan.

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Arun Jayaram, JPMorgan - Analyst [60]

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Yes, my question really regards the enhanced completion program in the Bakken, and I was wondering if you have tested these enhanced completion designs outside of the core, and if you could comment on any results, perhaps in some of your non-core tier 2 acreage in the Bakken?

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Gary Gould, Continental Resources, Inc. - SVP of Operations [61]

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This is Gary Gould, and slide 18 shows the different locations that we're showing these results on for the enhanced completions. And so the bottom line is we see that these enhanced completions are working every where in the Bakken, so what they are going to do is they're going to perform very well in the core, but they will expand the core, and they will bring what was previously uneconomic territory into being economic, even in the fringes of the play.

If you think about enhanced completions, what they do especially the ones in the Bakken where we are putting more proppant in the ground, they basically make a larger cross sectional area open to flow, such that it's a factor of improvement, and that doesn't matter which part of the play you're in. You're going to see that type of factor of improvement throughout the play, I believe.

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Glen Brown, Continental Resources, Inc. - SVP of Exploration [62]

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I might add, this is Glen Brown, that our enhanced completions are applying to not only the true Bakken, but also the Three Forks. So this is a multi-level enhanced completion effort that we're doing, for those that are less familiar.

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Jack Stark, Continental Resources, Inc. - President and COO [63]

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I'd point you to slide 18 for perspective. I think Gary just pointed it out, but just note that Maryland and Nashville, that's 40 miles west of the Antelope area that's on the East side. So when Gary says that we're seeing this uplift across a broad area, that's a pretty broad area. It's a big step out there applying those [stim], and we really seen equally good results out there.

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Arun Jayaram, JPMorgan - Analyst [64]

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Great and just my final question, as you look at the correlation between proppant loads, 1,000 pounds per lateral foot to 2,000, can you talk about the productivity gains and perhaps from those types of completion recipes, and what you're seeing in terms of the cost benefit around the cost of proppant versus larger completion size?

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Gary Gould, Continental Resources, Inc. - SVP of Operations [65]

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This is Gary Gould again, and we are always looking at the incremental rate of return for that incremental capital, so that's the way we will be assessing results. In the Bakken, just getting up now to the testing that range of a 1,000 to 2000 pounds per foot, because we don't have a lot of tests at the upper range yet, for what you're talking about. We will always be looking at it, and looking at the incremental rate of return for the incremental capital costs.

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Jack Stark, Continental Resources, Inc. - President and COO [66]

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We're always looking for that point at which we are going to hit the diminishing returns, and we've not seen that yet, but we need to get more tests in the ground. But there are other areas outside the Bakken where we've actually seen, as Harold mentioned, where we could actually reduce the amount of sand utilized, and get equal or even well, at least equal results as a bigger stim.

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Arun Jayaram, JPMorgan - Analyst [67]

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Thanks a lot.

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Operator [68]

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Our next question comes from the line of Pearce Hammond from Simmons.

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Pearce Hammond, Simmons & Company International - Analyst [69]

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Congrats on a solid 2016. John, my first question is, just curious what the milestones are to get to investment grade. And not trying to be flippant here in any way, but just curious why investment grade is important because the Company has really good assets and that speaks for themselves.

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John Hart, Continental Resources, Inc. - SVP, CFO and Treasurer [70]

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The reason it's valuable to us as we have three decades of inventory and the lower cost of capital and access to that capital has a tangible present value benefit to us in terms of our economics, if we can finance it at lower cost. We are cash neutral, and we plan on staying there, so we are not necessarily accessing the markets, but there will come times where we term out existing amounts or do other things with that, so it's valuable.

In regards to milestones Moody's put out a piece here recently where they put us on positive upgrade, so you can reference that, but getting down to $6 billion, as I referenced, is a good milestone. And content seeing continued improvement in strength in the commodity markets, will have a very tangible bit on us, not only in cash flow but also in terms of debt to EBITDA and other measures that they look at.

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Pearce Hammond, Simmons & Company International - Analyst [71]

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Excellent. Thank you, and that's it for me.

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Operator [72]

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Our next question comes from the line of John Freeman from Raymond James.

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John Freeman, Raymond James - Analyst [73]

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Just a follow-up on Pearce's question. So you all went over the sensitivity that you all have to even the small changes in the oil price and I guess if the oil price does do better, you end up with a good bit of excess cash. Do we just assume that until you get to that $6 billion type of a target, that's where the incremental cash goes as opposed to maybe your highest return moves, like Bakken ducks or STACK or something?

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John Hart, Continental Resources, Inc. - SVP, CFO and Treasurer [74]

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I think in the near term that's probably fair. As you go out over a longer period, there's optionality, where we may be looking to set up out years or other things to enhance. It really depends where the market is.

We'll take a balanced view and a balanced approach to it, and as you know, particularly watching the last couple years, we don't respond to short-term momentary spikes or falls in various ways. We take long term look on prices.

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John Freeman, Raymond James - Analyst [75]

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Great, and just one quick one for me. In the Bakken with the five frac crews going to eight by mid May, have those been secured, and if so, are any of those going to be on term contracts?

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Gary Gould, Continental Resources, Inc. - SVP of Operations [76]

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This is Gary Gould. Yes, those have been secured, and as far as term contracts, we continually work with each individual Company for the term, and so we maintain that relationship for as long as we need them.

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John Freeman, Raymond James - Analyst [77]

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Great thanks. Appreciate it.

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Operator [78]

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Our next question comes from the line of Marshall Carver from Heikkinen Energy.

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Marshall Carver, Heikkinen Energy Advisors - Analyst [79]

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Most of my questions were answered but how should we think about debt, asset sales and guidance? Last year, you were able to sell assets with little production, and therefore minimal impact on guidance. Do you have a time frame for those additional asset sales, and would they likely have production associated with them? And is that cooked into guidance?

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Harold Hamm, Continental Resources, Inc. - Chairman and CEO [80]

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Marshall, typically have we sold assets that basically you didn't even know about. It was acreage that we picked up in areas that are in plays. It's good acreage, it's way out on our inventory, past 10 years perhaps, that we select that has good value in the market, and that we can monetize and pick a time to do that, so that's really what we target, and what's what we will target again. And I think the $6 billion, we have plenty of things out there to get there.

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John Hart, Continental Resources, Inc. - SVP, CFO and Treasurer [81]

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The ones we're looking at now don't have production associated with them, so there's no impact there. The ones we sold last year all-in had maybe 3,000 a day of production, so you certainly could have seen a little higher production in the fourth quarter, if we hadn't done that, but typically, we hold on to PDP.

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Marshall Carver, Heikkinen Energy Advisors - Analyst [82]

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All right, well thank you, and amazing that you all could have that much value hidden away.

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John Hart, Continental Resources, Inc. - SVP, CFO and Treasurer [83]

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We got more.

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Marshall Carver, Heikkinen Energy Advisors - Analyst [84]

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Thank you very much.

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Operator [85]

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This does conclude the question-and-answer session of today's program. I'd like to hand the program back to Warren Henry for any further remarks.

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Warren Henry, Continental Resources, Inc. - VP of IR [86]

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Once again, I'd like to thank you all for joining us on today's call, and we look forward to reporting another strong quarter in just a couple months in early May. So thanks, and have a great day.

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Operator [87]

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Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.