Continental Resources (CLR) Q4 2016 Results - Earnings Call Transcript

| About: Continental Resources, (CLR)

Continental Resources, Inc. (NYSE:CLR)

Q4 2016 Earnings Call

February 23, 2017 12:00 pm ET

Executives

J. Warren Henry - Continental Resources, Inc.

Harold G. Hamm - Continental Resources, Inc.

Jack H. Stark - Continental Resources, Inc.

John D. Hart - Continental Resources, Inc.

Glen A. Brown - Continental Resources, Inc.

Gary E. Gould - Continental Resources, Inc.

Analysts

Brian Singer - Goldman Sachs & Co.

Brian Michael Corales - Howard Weil

Edward George Westlake - Credit Suisse Securities (NYSE:USA) LLC

Stephen Fred Berman - Canaccord Genuity, Inc.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Arun Jayaram - JPMorgan Securities LLC

Pearce Hammond - Simmons Piper Jaffray

John A. Freeman - Raymond James & Associates, Inc.

Marshall H. Carver - Heikkinen Energy Advisors LLC

Operator

Good day, ladies and gentlemen, and welcome to the Continental Resources, Inc. Fourth Quarter 2016 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. 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 Investors Relations. Please go ahead, sir.

J. Warren Henry - Continental Resources, Inc.

Thank you, Jonathan. And thanks 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-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 in this call, we will refer to initial production levels for new wells, which in most cases are maximum 24-hour initial test rates.

Finally, on the call, we will refer to certain non-GAAP financial measures. For a reconciliation of these measures to Generally Accepted Accounting Principles, please refer to the updated investor presentation that has been posted on the company's website at www.clr.com.

With the preliminaries covered, I will turn the call over to Mr. Hamm. Harold?

Harold G. Hamm - Continental Resources, Inc.

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 and a second year of volatile commodity markets. Now, we are pleased to be transitioning into stronger commodity markets that are reflective of both 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've 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. In STACK, we demonstrated the over-pressured window, as yet another cornerstone asset and establish STACK as the 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 over-pressured 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 1-15-10XH well, our first test of the over-pressured condensate window. The Boden IP'd 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 be a dry gas well. Then, throughout the remainder of 2016, we continued to derisk our leasehold, focusing mainly on the over-pressured oil window.

Once again, our exploration success is clear and striking. Today, STACK is firmly established as one of the premier onshore U.S. 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 and enhanced completion designs.

As noticed in the yesterday's release, advancement and completion technology enabled Continental to set new company well production records in all of the plays, STACK, SCOOP and Bakken. From our 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 in the past year was our activity in North Dakota Bakken where we've 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 coming 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 balance with cash. Our strategy remains disciplined spending and balance sheet management to deliver fully full value to the shareholders.

Today, the significance of 2016 and its achievements, of course, has had set 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 our prospects for the company. And given that 2017 marks our 50th year in business, it 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 strong results in the new year.

With that overview, I'll turn the call over to Jack Stark.

Jack H. Stark - Continental Resources, Inc.

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 set 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 that 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 continue to achieve excellent results from our Meramec drilling. In all, we completed another seven operated Meramec wells in the over-pressured oil window, with initial rates ranging from 1,600 Boe per day to 2,500 Boe per day, at flowing casing pressures up to 3,900 psi in 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 the presentation on our website.

To-date, we have de-risked approximately 47,000 net acres in the over-pressured oil window and this area contains 55 operated 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 over-pressured 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 in 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 ranging from 5,900 psi to 7,500 psi from their 9,700 from 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 complete 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 onto 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 cost 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 de-risked 47,000 net acres in the over-pressured 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've 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 a 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 costs 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 for a $7,500 per 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 includes the Boatright and Peppered Ranch wells. The Boatright flowed an impressive 3,460 Boe per day at 3,160 psi from 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.

In the SCOOP oil window, we recently completed the Emery, which flowed 1,330 Boe per day at 500 psi pressured from 9,700 foot lateral and 77% of the production was oil. The Emery was completed with tighter stage spacing and more proppant per foot than it's offset.

Now, before I turn the call over to John, I want to provide a couple of highlights on our 2017 budget. First, our 2017 drilling completion program is oil weighted. Approximately 82% of the capital was allocated to Bakken and STACK, which would 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 three-stream reporter like many of our peers.

Second, the budget only includes one additional drilling rig. However, our completion crew count in 2017 increases significantly. In the Bakken, we're 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'll also complete an additional 72 Bakken wells that we'd 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've modeled in a 5% to 10% increase in cost by year-end 2017. Now, 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 technology. We're anxious to see that improvements of these technologies to well deliver and we use the results to optimize our development and 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 thick and 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.

John D. Hart - Continental Resources, Inc.

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 percent 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 fourth quarter, we divested certain non-core largely non-operated assets in SCOOP for $296 million and recognized the 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 cost 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 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 a Boe.

Fourth quarter G&A, excluding equity compensation was $2.21 per Boe. Non-cash equity compensation was $0.72 per Boe of production or a 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 leased 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're in good shape. As a reference point, a move in WTI for us of about $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 Boe per day 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 Boe and 215,000 Boe per day.

During the first quarter, we're likely around the midpoint of this range, due to severe weather in the Bakken impacting January production. The good news is that production is quickly recovered to approximately 215,000 per 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 online, drilling into our expected exit rate of 250,000 Boe to 260,000 Boe 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 and inventory are net of working down our uncompleted well inventory, while also adding new wells from drilling. The key takeaway is that the capital we spend in 2017 not only benefits the current year, but will be a catalyst for multi-year growth. We're 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're choosing to remain conservative in 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 over-pressured oil window. In Bakken, in late 2016, we began working down our large inventory of uncompleted wells, which will aid 2017 and 2018's 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.

Question-and-Answer Session

Operator

Thank you. Our first question comes from the line of Brian Singer from Goldman Sachs. Your question, please.

Brian Singer - Goldman Sachs & Co.

Thank you. Good afternoon.

John D. Hart - Continental Resources, Inc.

Hey, Brian.

Harold G. Hamm - Continental Resources, Inc.

Good morning.

Brian Singer - Goldman Sachs & Co.

Good morning, yes, so still morning in the Central Time zone. 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 DUCs are completed and how strategic is your acreage in STACK gas window once that area is delineated?

John D. Hart - Continental Resources, Inc.

If I missed some of that, feel free to come back again. If you look back to the back half of 2015, and then, certainly, through the bulk of 2016, we weren't completing our 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're 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 areas, that dotted line on our chart on the investor slide deck, that's an oil heavy area, we've seen some 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 tremendous results. So that's a multi-year growth and that's why we tried to give you that color and transparency going out into the future.

Brian, I'm sorry, you had a lot there. If you can give me your other aspects?

Brian Singer - Goldman Sachs & Co.

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

Jack H. Stark - Continental Resources, Inc.

Brian, this is Jack. Yeah, the Anderson Half well, as you can see, was a very impressive and prolific well, and it was so good that we felt that we needed to step back and see if we couldn't confirm those kind of rates, and we did with the two offsets. And so, we're very comfortable that we have a very significant gas asset there. But we're comfortable now that we're going to be able to HBP that with the drilling that we're doing underneath our Northwest Cana JDA that we've got with SK.

And so, we're probably not going to do is a lot of drilling down there in 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.

Brian Singer - Goldman Sachs & Co.

Thanks. And then, maybe just one more on SCOOP and STACK. It seems like there is 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?

Jack H. Stark - Continental Resources, Inc.

Well, as far as – there's three of us stepping up to this one. I'll just say that productivity improvements, I mean 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 is 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 even back off on some of these stims and do as well.

Harold G. Hamm - Continental Resources, Inc.

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

Glen A. Brown - Continental Resources, Inc.

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 are just reminding everybody that we have a shallow part and a deep part of the play. Our reservoirs are twice as thick as the normal pressured play. We have twice as much pressured in our over-pressured 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.

Brian Singer - Goldman Sachs & Co.

Great. Thanks so much for the color.

John D. Hart - Continental Resources, Inc.

Thanks, Brian.

Operator

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

Unknown Speaker

Hey, guys. Good morning. This is Clay (34:45) on for Doug. Thanks for taking my question. My first question is on the Bakken DUC wedge. So you guys have previously guided to about 30,000 Boe to 40,000 Boe per day by year end as the contribution from that DUC inventory. Can you talk about what type curve is embedded into that assumption, whether that's different than the 980 MBoe type curve that characterizes your DUCs.

Basically, what I'm trying to understand is, whether there is 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 that you guys are showing.

Gary E. Gould - Continental Resources, Inc.

Yes. This is Gary Gould. What we've baked into it is that 980 MBoe type curve for the DUCs and 920 MBoe type curve for our newest drill wells that we're targeting this year. We're drilling a different part of the core compared to where we're 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 profit. 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 is still room to grow as far as how we're optimizing our completions.

John D. Hart - Continental Resources, Inc.

Clay (36:01), that wedge that we gave, the 30,000 Boe to 40,000 Boe, that's based just on the DUCs. By the end of the year, we're pretty much moving away from that term DUC. We're moving more back into wells in progress and getting back to 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.

Unknown Speaker

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

John D. Hart - Continental Resources, Inc.

All of them.

Unknown Speaker

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 IP24 basis. Just trying to understand what's driving that, typically looking at the winter still well, which provided the lowest rate, but also with an extended lateral. So I'm guessing that lateral length doesn't seem to tell the whole story, so I'm just wondering what's going on there.

Glen A. Brown - Continental Resources, Inc.

Well, let me – this is Glen Brown. Let me address the seven wells in general. We do have a mixture of different lateral lengths. So more short 1 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 at an average flowing pressure of 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 a geosteering anomaly, occasionally, we get it in and out of zone. We're still working in crafting our trade there and getting better on each and every well as we go forward.

Unknown Speaker

Got you. I appreciate the comments guys.

John D. Hart - Continental Resources, Inc.

Right. Thank you.

Jack H. Stark - Continental Resources, Inc.

Thanks, Doug (sic) Clay (38:11)].

Operator

Thank you. Our next question comes from the line of Brian Corales from Howard Weil. Your question, please.

Brian Michael Corales - Howard Weil

Good morning, guys. This is maybe more of a general question on enhanced completions. I mean, obviously, the more proppant and diverters have worked up in the Bakken. Are you all still testing like the outer extensive more proppant and other things to even further enhance completions?

Gary E. Gould - Continental Resources, Inc.

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

Brian Michael Corales - Howard Weil

Yeah. No, that's helpful. And then, I guess I would assume you're further along the Bakken and as you go to the STACK and probably even 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?

Gary E. Gould - Continental Resources, Inc.

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

Brian Michael Corales - Howard Weil

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 the wells in your plays keep getting better versus what you all put out in guidance a couple of weeks ago versus the outlook for 2017 and 2018, I'm assuming it's not all baked in.

John D. Hart - Continental Resources, Inc.

I think it's fair to – 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.

Brian Michael Corales - Howard Weil

All right, guys. Thank you. And good job on the quarter.

Jack H. Stark - Continental Resources, Inc.

Thanks, Brian.

John D. Hart - Continental Resources, Inc.

Thanks.

Operator

Thank you. Our next question comes from the line of Edward Westlake from Credit Suisse. Your question, please.

Edward George Westlake - Credit Suisse Securities (USA) LLC

Yeah, two questions. First one is, again, on the Bakken theme of the work that you guys have done and the industry in improving completions. As you've done this, presumably, there is 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? I guess, how many wells you could drill at 920 MBoe or 980 MBoe?

Jack H. Stark - Continental Resources, Inc.

Well, we've got, we've got 15 years at least that we could drill with what 15 rigs, and we're with four rigs right now. So inventory is not an issue, that's at an average 775 MBoe equivalent. I don't have a number for you that would be in that average 980 MBoe, but what we – but we've got a couple of decades of inventory up there and really delivering these type of results for the next five-plus years, it's not a problem. But what we can tell you is that when you think about what these enhanced teams are actually doing, they're 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 we had those step-outs, so we drilled in Maryland and Nashville, and we went way out 40 miles west of down there in our Antelope area and saw substantial uplifts there (41:50) of those wells relatively offsets, and so, I think bottom line is that I think what is core today is continuing to expand.

Edward George Westlake - Credit Suisse Securities (USA) LLC

That's what I was trying to get at. The other aspect is 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 maybe a constraint as the whole industry gets back to work or not, and any comments on sort of finer mesh versus coarse?

Gary E. Gould - Continental Resources, Inc.

Yes, Gary Gould again. And we do many things that help us be prepared for our sand design. So first of all, we work with many different vendors in both the north and the south. In 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 space and the use of the diverter, and so, our teams are always looking at all of that and again, right now, I think that optimum range is going to be not at the 3,000 or higher. I think it's going to be 2,000, 2,500 or below in pounds per foot. And so, I don't foresee a challenge associated with bringing sand to a location.

Harold G. Hamm - Continental Resources, Inc.

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

Glen A. Brown - Continental Resources, Inc.

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

Edward George Westlake - Credit Suisse Securities (USA) LLC

Yeah.

Glen A. Brown - Continental Resources, Inc.

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

Edward George Westlake - Credit Suisse Securities (USA) LLC

Okay. Thank you very much.

Harold G. Hamm - Continental Resources, Inc.

Thank you.

Operator

Thank you. Our next question comes from the line of Steve Berman from Canaccord. Your question, please.

Stephen Fred Berman - Canaccord Genuity, Inc.

Thank you. Jack, I think I heard you talk about maybe testing some other formations in Oklahoma during the course of the year. I guess, almost by process of elimination Osage/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 bit more about what you might do there?

Jack H. Stark - Continental Resources, Inc.

Sure. I mean those are, obviously, two reservoirs that exist in this system that are very high potential and yeah, they would be included in the list of zones we're testing and 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 in reservoirs. And so, through the year, you'll see us we'll be doing some testing and depending on the pace of which we can get those tests on, we'll share some of those results.

Stephen Fred Berman - Canaccord Genuity, Inc.

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

Gary E. Gould - Continental Resources, Inc.

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

Harold G. Hamm - Continental Resources, Inc.

And we've mentioned Steve that we have protected the company with hedges.

Stephen Fred Berman - Canaccord Genuity, Inc.

Okay, excellent. Thank you, gentlemen.

Harold G. Hamm - Continental Resources, Inc.

Thank you.

Glen A. Brown - Continental Resources, Inc.

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

Operator

Thank you. Our next question comes from the line of Neal Dingmann from SunTrust. Your question, please.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Hi, guys. I did have a sort of question follow-up to what somebody had asked earlier. My question is really about how you guys look at, Harold for you or Jack, kind of your choke management program, it seems like a lot of us on Wall Street focus a lot on IP30 or IP60s 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 which you'll deem those deeper STACK tests?

Harold G. Hamm - Continental Resources, Inc.

I'm going to turn it over to Gary and let him – it is pretty complex and I just let Gary run through it for you.

Gary E. Gould - Continental Resources, Inc.

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 where we shut back oil production because of the price. And so, last year, there's a lot of times where we were not really in a position where we wanted to increase the rates through a more aggressive choke management. And so, what we're doing this year, let's take the Bakken to begin with, is multiple things. We've got the enhanced completions that's working to increase the reserves and increase the rate. And we've got two other mechanisms that are working to increase the rate at the beginning of the wells' life.

First back – the first of those two is more aggressive choke management, and then, the second piece is higher rate production lift. And so, we're 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 over-pressured area is we've got such strong pressures that those pressures are able to continue to drive 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 over-pressured nature of that reservoir.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

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

Gary E. Gould - Continental Resources, Inc.

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

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Okay. And then, just one last follow-up for me if I could guys. How do you look at – I'm looking at slide I think 14 on your last decks, that shows the density test and the Meramec over-pressure, and so, I guess what I'm wondering is if you look – starting with Ludwig, and then, going west, what type 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 Meramec zones in that area?

Jack H. Stark - Continental Resources, Inc.

I'll actually refer you to a slide. I think we got an appendix here...

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Okay.

Jack H. Stark - Continental Resources, Inc.

...page 29 and what it shows is 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 can see it ranges anywhere from 675 foot thick total to about 785 foot thick and each of these right now we're looking in this particular area we're targeting upper and the 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 got anywhere from three to four to five and even six wells that we'll be testing there in the Angus Trust per zone.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Jack, would the thickness – it can be silly question, would the thickness of the gas to deep STACK be about the same or would that be a bit thicker than this page 29?

Jack H. Stark - Continental Resources, Inc.

No. You get substantially thicker as you go down to the Southwest. This particular system here where we're showing about say 750 feet thick here, if you go down there, Glen, it's what about 1,200 feet thick and so, you can see, it's not quite a double, but pretty close.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Got it.

Jack H. Stark - Continental Resources, Inc.

So that's one of the big drivers down there is that you got this extreme over-pressure. You're looking at 0.8 psi per foot pressure gradient and on top of that, you got almost double the thickness. And so, when Glen was saying that ZIP code matters and that being in the right area where the reservoirs best developed, it definitely is critical and as you move down to the south and west there, we're getting thicker and even better quality.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Great. Thank so much for the details guys.

Operator

Thank you. Our next question comes from the line of Arun Jayaram from JPMorgan. Your question, please.

Arun Jayaram - JPMorgan Securities LLC

Yes. My question really regards just the enhanced completion program in the Bakken and I was wondering if you guys 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 kind of acreage in the Bakken?

Gary E. Gould - Continental Resources, Inc.

This is Gary Gould, and we've got a slide, I think slide 18 that shows kind of the different locations that where we're showing these results on for enhanced completions. And so, the bottom line is we see that these are enhanced completions we're working everywhere in the Bakken. And so, what they're going to do is they're going to perform very well in the core, but they will expand the core and I think 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're putting more profit in the ground, they basically make a larger cross sectional area open to flow such that it's a factor of improvement, 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.

Glen A. Brown - Continental Resources, Inc.

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 efforts that we're doing (53:17).

Arun Jayaram - JPMorgan Securities LLC

Yeah. Great.

Jack H. Stark - Continental Resources, Inc.

And I'd point you to slide 18, just from a 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 the broad area, that's a pretty broad area. That's a big step out there applying those stims and we really have seen equally good results out there.

Arun Jayaram - JPMorgan Securities LLC

Great. And then, just my final question, as you look at the correlation between proppant loads, call it, 1,000 pounds per lateral foot to 2,000 pounds per foot, 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 profit versus larger completion size?

Gary E. Gould - Continental Resources, Inc.

It's 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 testing at a range of 1,000 pounds per foot to 2,000 pounds per foot, we don't have a lot of test at the upper range yet for what you're talking about. We'll always be looking at it and looking at the incremental rate of return for that incremental capital to cost.

Jack H. Stark - Continental Resources, Inc.

Yeah. We're always looking for the point at which we're going to hit diminishing returns and we've not seen that yet, but we need to get more tests in the ground, but there are some other areas outside of 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 is a bigger stim.

Arun Jayaram - JPMorgan Securities LLC

Okay. Thanks a lot gents.

Jack H. Stark - Continental Resources, Inc.

Thanks.

Harold G. Hamm - Continental Resources, Inc.

Thank you.

Operator

Thank you. Our next question comes from the line of Pearce Hammond from Simmons. Your question, please.

Pearce Hammond - Simmons Piper Jaffray

Hi, good morning and 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 flipping here in anyway, but I'm just curious why investment-grade is important, because the company has really good assets and that sort of speaks for themselves?

John D. Hart - Continental Resources, Inc.

The reason it's valuable to us is 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're not necessarily accessing the markets, but there will come times where we'll 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 some positive upgrade, so you can reference that, but I think getting down to $6 billion, as I referenced, is a good milestone and seeing continued improvement and strength in the commodity markets will have a very tangible bid on us, not only cash flow, but also in terms of debt to EBITDA and other measures that they look at.

Pearce Hammond - Simmons Piper Jaffray

Excellent. Thank you and that's it from me.

John D. Hart - Continental Resources, Inc.

Thank you.

Operator

Thank you. Our next question comes from the line of John Freeman from Raymond James. Your question, please.

John A. Freeman - Raymond James & Associates, Inc.

Hi, guys.

Harold G. Hamm - Continental Resources, Inc.

Good morning.

John D. Hart - Continental Resources, Inc.

Hey, John.

John A. Freeman - Raymond James & Associates, Inc.

Hi. Just a follow-up on Pearce's question, so you all went over sort of 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 kind of 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, DUCs or STACK or something?

John D. Hart - Continental Resources, Inc.

I think in the near-term that's probably fair. As you go out over a longer period, there is 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, I think you particularly watched in the last couple of years, we don't respond to short-term momentary spikes or falls in various ways, we take a long-term look on prices.

John A. Freeman - Raymond James & Associates, Inc.

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

Gary E. Gould - Continental Resources, Inc.

This is Gary Gould. Yes, those have been secured and as far as term contracts, we're continuously working with each individual companies with the term. And so, we maintain that relationship for as long as we need them.

John A. Freeman - Raymond James & Associates, Inc.

Great. Thanks guys, appreciate it.

John D. Hart - Continental Resources, Inc.

Thank you.

Harold G. Hamm - Continental Resources, Inc.

Thank you, John.

Operator

Thank you. Our next question comes from the line of Marshall Carver from Heikkinen Energy. Your question, please.

Marshall H. Carver - Heikkinen Energy Advisors LLC

Yes. Thank you. 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, therefore, minimal impact on guidance. Do you have a timeframe for those additional asset sales and will they likely have production associated with them, and is that cooked into guidance?

Harold G. Hamm - Continental Resources, Inc.

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

John D. Hart - Continental Resources, Inc.

And the ones we're looking at now don't have production associated with them, so there is no impact there. The ones we sold last year, I think all-in had maybe 3,000 Boe 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.

Marshall H. Carver - Heikkinen Energy Advisors LLC

All right. Well, thank you and amazing that you'll could have that much value hidden away.

John D. Hart - Continental Resources, Inc.

We got more.

Marshall H. Carver - Heikkinen Energy Advisors LLC

Thank you very much. Bye.

John D. Hart - Continental Resources, Inc.

Bye. Have a good day.

Harold G. Hamm - Continental Resources, Inc.

Thank you.

Operator

Thank you. And 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.

J. Warren Henry - Continental Resources, Inc.

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 of months in early May. So thanks, and have a great day.

Operator

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

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