Continental Resources, Inc.

J. Warren Henry - Vice President-Investor Relations & Research Harold G.

Hamm - Chairman & Chief Executive Officer Jack H. Stark - President & Chief Operating Officer John D.

Hart - Chief Financial Officer, Treasurer & SVP Gary E. Gould - Senior Vice President, Production and Resource Development Glen A.

Brown - Senior Vice President, Exploration Pat Bent - Vice President-Northern Drilling & Completions Steven K. Owen - Senior Vice President-Land

Brian M. Corales - Scotia Howard Weil Brian Singer - Goldman Sachs & Co.

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

Subash Chandra - Guggenheim Securities LLC Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Stephen Fred Berman - Canaccord Genuity, Inc. Drew E.

Venker - Morgan Stanley & Co. LLC Doug Leggate - Bank of America Merrill Lynch Neal D.

Dingmann - SunTrust Robinson Humphrey, Inc. Marshall Hampton Carver - Heikkinen Energy Advisors LLC Derrick Whitfield - GMP Securities LLC Arun Jayaram - JPMorgan Securities LLC

Thank you, Abigail. Thank you, everyone, for joining us this morning.

I'd like to welcome everyone to today's call. Joining us today with prepared remarks are 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 this morning 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 Vice President, Drilling; Glen Brown, Senior Vice President, Exploration; Gary Gould, Senior Vice President, Production & Resource Development; and Steve Owen, Senior Vice President of Land. Our call today will contain forward-looking statements that address projections, assumptions, and guidance.

Actual results may differ materially from those contained in our forward-looking statements. Please refer to the company's filings with the Securities and Exchange Commission for additional information concerning these statements and risks.

In addition, Continental does not undertake any obligation in the future to update our forward-looking statements made on this call. In addition, on this call, we will refer to initial production levels for new wells.

These are maximum 24-hour initial test rates. Finally, on the call, we will refer to certain non-GAAP financial measures.

For reconciliation of these to generally accepted accounting principles, please refer to the updated investor presentation that has been posted on our website at www.clr.com. Now to begin this morning's commentary, I will turn the call over to Mr.

Hamm.

Thank you, Warren. Good morning, everyone.

Three months ago, we summarized our first quarter of 2016 as being highlighted by rock-solid performance of our top-tier assets and people, strong production, excellent well results, reduced operating costs and capital spending discipline. Well, our second quarter results were more of the same except better, excellent performance across the board.

Production for the second quarter was strong as we continue to see exceptional performance from enhanced well completions in the Bakken, STACK and SCOOP plays. As a result, we again raised production guidance for 2016 as a whole, while lowering our guidance on operating expenses.

We've reduced our production expense guidance by $0.50 per Boe, below the previous range. Cash G&A expense is now expected to be $1.20 per Boe to $1.60 per Boe.

Finally, our expectation for 2016 oil differential has improved to a range of $7 per barrel to $8 per barrel. Next, we continued the high-grade or asset portfolio with an agreement to sell 29,500 acres of non-strategic SCOOP leasehold for $281 million.

We will use this $281 million in proceeds to reduce debt. As you will remember, this is our second asset sale this year.

We have additional opportunities to monetize non-strategic assets, especially for undeveloped leaseholds outside our 10-year drilling plan. Continental is routinely contacted by other operators concerning assets that are non-strategic for us, but represents significant value to other operators development plans.

We have the opportunity to bring significant value forward to deleverage our balance sheet. Before Jack gets into the detail of our second quarter achievements, I'd like to give you a sense for our priorities for the second half of this year.

First, we continue to see world oil markets rebalancing throughout 2016. Short term, there's some market volatility as the inventory overhang of crude oil and refined product begins to diminish and traders respond to reduced seasonal demand period with OPEC production running flat out.

Continental is dealing with this new market reality, as are others in the industry, by curtailing oil production and drilling and completion activity in certain areas. The current environment underlines more than ever the importance of the company's discipline and strong execution.

Our priority remains cash flow neutrality, no new debt and balancing capital spending with cash flow through the second half of this year, while maintaining production and building proved reserves. Next, we're working to improve the company's leverage metrics including reducing level of long-term debt on our balance sheet.

Our target is a number of $6 billion or less, our primary opportunity in this period is through non-strategic asset sales followed by increased cash flow as oil and natural gas prices do recover. Our second priority through the remainder of the year is continued efficiency improvement.

We are focused on expense reduction especially structural efficiency improvements that we can sustain in an improved oil price environment. Our teams, both North and South, have done a tremendous job in the past 18 months reducing well costs and operating expenses across the board as is evident from our guidance this quarter.

New hiring has been limited to exceptional needs as our employee count has reduced the attrition. We're continuing to adjust and optimize our enhanced completion techniques.

We've decided to complete eight additional gross wells in the Bakken, testing other enhanced completion designs and diverter technology. These tests and results obtained from them will prove very valuable at the time we start completing the Bakken DUCs.

Continental's operating strategy produced industry-leading results in the first half of 2016, and we anticipate even stronger second half results, especially if oil prices resume their upward trend, as we expect. As I said, our teams are operating at an exceptionally high level, and we, on the executive team, couldn't be prouder of their commitment, enthusiasm, and stellar results.

We've seen a step change in the company's operating performance. Continental is uniquely positioned to thrive with top-quartile assets, industry-low operating costs, and disciplined execution.

Don't forget that we are an exploration company. Four years ago, we drilled a few really nice wells in the South Driftwood area in the SCOOP Woodford oil window.

Our Evans and Hansel wells were the forerunners of a series of wells drilled there and improved through enhanced completions, which has uplifted the well performance in a very large acreage area. Our latest well, the RK Morris, is also representative of this area, and Jack will go on to further detail and give you the inside scoop.

With that, I'll turn this call over to Jack.

Thank you, Harold, and good morning, everyone. We appreciate you joining us on our call today.

We have great operational news to share from the second quarter. But before I get into the details, I want to elaborate a bit more on Harold's comment regarding the step change in capital efficiencies that Continental has achieved.

So, let me put some numbers on it. Over the last 18 months, the barrels of oil equivalent found per dollar invested has increased to 133% compared with full year 2014.

Over the same period, production expense per barrel of oil equivalent and G&A expense per barrel of oil equivalent had decreased 36%. This is a remarkable improvement in capital and operating efficiency, but even more important, we believe the majority of these efficiencies are structural and sustainable, which will strengthen Continental's performance going forward.

I point this out to be sure that our shareholders and potential shareholders appreciate the significance of this step change as it's the best indicator of our future performance. Now, let's get into the second quarter operating highlights, starting with STACK.

It's hard to believe that it was only one year ago that we announced the completion of our first Meramec well in STACK. Since then, we have completed 15 operated Meramec wells, derisked more than 300 square miles of the play, successfully tested three Meramec zones, demonstrated excellent repeatability, reduced drilling times by more than 40%, reduced well cost by approximately 20%, applied enhanced completions to boost recoveries, and today, we're in the process of completing the first density pilot, including microseismic monitoring to assess the effectiveness of our stimulations.

On top of all of this, we also added approximately 47,000 net acres of STACK leasehold during the past year, bringing our total leasehold position to 183,000 net acres as of June 30. Most of this was low cost, legacy acreage and approximately 60% will be held by production by year-end 2016.

We currently have 11 operated rigs drilling in the play with 17 Meramec and 9 Woodford wells completing or waiting on completion. Production from STACK now represents 7% of the company's total production, and the outstanding well performance is a key contributor to our updated guidance.

Finally, to top all of this off, we estimate that STACK could add as much as 25% to our net unrisked resource potential. All of this in one year and all of this is incremental to the company.

Pretty impressive I have to say and we're just getting started. Looking specifically at the second quarter, we completed five Meramec wells in STACK, four in the over-pressured oil window and one in the over-pressured gas window.

In the over-pressured oil window, we extended the known productive footprint 17 miles to the west of our Verona well with the Madeline 1-9-4XH and the Frankie Jo 1-25-24XH wells. Madeline flowed at a company record rate of 3,538 barrels of oil equivalent per day at 4,500 pounds per square inch flowing casing pressure, and 71% of the production was oil.

The Frankie Jo was completed flowing 2,627 barrels of oil equivalent per day at just over 4,300 pounds flowing casing pressure and 56% of the production was oil. Both were approximately 2-mile laterals with the Frankie Jo being our westernmost completion to-date.

The other two oil window wells were strong confirmation wells, just Southeast of the Verona well. The Gillilan 1-35-26XH flowed 2,439 barrels of oil equivalent per day at 2,000 pounds flowing casing pressure, with 70% of the production being oil.

The Oppel 1‐25‐24XH flowed 1,308 barrels of oil equivalent per day at 1,700 pounds flowing casing pressure, and 76% of the production was oil. The Gillilan was drilled with a 900-foot lateral and the Oppel's lateral was just a little over 7,100 feet.

During the second quarter, we also completed our first well in the over-pressured Meramec gas window, the Yocum 1-35-26XH. The Yocum is an excellent gas producer and flowed 14 million cubic feet of gas per day and 17 barrels of oil per day at more than 4,800 pounds flowing casing pressure.

During its first 104 days online, the Yocum has produced 1.1 billion cubic feet of gas and it continues to flow at almost 10 million cubic feet of gas a day with basically no oil at 2,500 pounds flowing casing pressure. Now, we drilled the Yocum specifically to test the productivity of the Meramec on the down-thrown side of the significant North-South trending fault.

This fault separates the Yocum from the company's previously announced Boden 1-15-10XH well, which is just over a mile to the Northwest. This separating fault has up to 525 feet of vertical displacement and clearly places the Yocum in the gas window.

In contrast, the Boden is located in the condensate window on the fault's up-thrown side. And as you may recall, the Boden completed flowing 1,000 barrels of oil per day and 15 million cubic feet of gas per day.

And since December of last year, it has produced an impressive 361,000 barrels of oil equivalent, of which 27% was crude oil, and it continues to flow 1,240 barrels of oil equivalent per day at 4,200 pounds flowing pressure with 26% of the production being oil. The Yocum results support our geologic model for the STACK petroleum system and place an additional 2% of Continental STACK acreage in the gas window.

Based on subsurface well control and 3D seismic coverage, we see no other fault of this magnitude underneath our STACK acreage. Now, as I mentioned, we have 11 rigs drilling in STACK with six targeting the Meramec and five targeting the Woodford under our Northwest Cana JDA with SK E&S.

Our Meramec drilling is focused on two objectives; one, we want to expand our understanding of the productive extent and hydrocarbon content of the Meramec reservoirs; and two, we want to establish the optimum drilling density for the over-pressured STACK reservoirs. As I noted, we are currently completing our first STACK density pilot in the over-pressured oil window at the Ludwig unit.

As a reminder, we are testing four wells per zone in the Upper and Middle Meramec reservoirs with one additional well in Woodford. This includes the parent well, the Ludwig 1-22-15XH, which produced 279,000 barrels of oil equivalent during its first 310 days on line with 74% of the production being oil.

I should point out that we have not always produced the Ludwig parent well to its full potential during these 310 days, due to low oil prices. And today, it is shut in for completion of the new density wells around it.

Average lateral length for the Ludwig density wells is approximately 9,500 feet and we expect to have results for the density pilot in the fourth quarter. The Ludwig density pilot was our first opportunity to realize efficiency gains from pad development in STACK, and we reduced both drilling times and drilling costs for the new wells.

The STACK team reduced spud to TD times by 44% over the average STACK well drilled in 2015. They also cut average drilling cost 28% from the Ludwig legacy well drilled last summer, coming in at an estimated $3.2 million per well.

Based on these advances and experience, our STACK team is now targeting an average completed well cost of $9 million for an extended lateral in the over-pressured oil window by year-end 2016. This is $500,000 below the previous year-end 2016 target and delivers an 85% rate of return at $45 per barrel of WTI and $2.50 per million cubic feet of gas based on an estimated ultimate recovery of 1.7 million barrels of oil equivalent per well.

I should also mention we've begun drilling our second and third STACK density pilots in the over-pressured oil window at the Bernhardt and Blurton units, which are located 3 to 4 miles Northwest of Ludwig. The Bernhardt density is a five-well per zone pattern in the Lower Meramec with targeted lateral lengths of 4,500 feet.

The Blurton density is testing three to five wells per zone in the Upper and Lower Meramec, with targeted lateral lengths of 9,800 feet. One thing I need to point out in STACK before I move on is our STACK land team, they continue to do an excellent job building Continental's leasehold position in the play.

Our 183,000 net acres of STACK leasehold includes 12,000 net acres added in the second quarter of 2016. Approximately 95% of our STACK leasehold is located in the over-pressured window of STACK and we estimate 40% of this acreage now lies within the over-pressured oil window.

This is up 10% from our previous estimate of 30% in the oil window. In addition, we estimate that another 40% is in the condensate window and 20% in the dry gas window.

Now, let's move on to SCOOP Woodford where the big news there, once again, is enhanced completions. Consistent with what we've seen in the Woodford condensate window, enhanced completions in the Woodford oil window are now delivering significantly improved repeatable results that compete economically with our other assets.

As we announced in our press release, we have increased our expected EUR for wells drilled in the Woodford oil window by 30% to 1.3 million barrels of oil equivalent per well assuming a 9,800 foot lateral, with 62% of the total production being oil. The increase is based on the results of 22 enhanced completions in the Woodford oil window that showed 180-day production rate increases on the average of 25% to 30% compared with offsetting legacy wells.

At a targeted cost of $9.8 million per well, a 1.3 million barrel oil equivalent Woodford oil well yields a 32% rate of return at $45 oil and $2.50 gas. Our recently completed RK Morris 1-29-17XH in eastern Grady County is a great example.

The well completed flowing 1,003 barrels of oil and 1.8 million cubic feet of natural gas per day from an 11,500-foot lateral, with flowing casing pressure of 690 pounds, along with strong initial production of wells exhibiting a low decline rate with an average 30-day production of 903 barrels of oil and 1.6 million cubic feet of natural gas per day at 560 pounds flowing casing pressure. Approximately a third of our 413,000 acres in SCOOP Woodford is located within the Woodford oil window.

Based on the current distribution of these enhanced completed results, we believe at least 50,000 net acres can be upgraded to the 1.3 million barrels of oil equivalent model. We expect this model will apply to more acreage as we expand the footprint of our enhanced completions.

This is obviously a significant value-add to our Woodford assets. Now, let's turn to the Bakken in North Dakota.

We recently elected to complete eight additional operated Bakken wells in the second half of 2016 to test new completion techniques. In particular, we wanted to further test the impact of stage spacing, proppant loads, proppant size and diverter technology on well performance.

We wanted to understand to what degree these technologies will improve the well performance to optimize future development of our growing inventory of DUCs. We have deployed two stimulation crews and expect first production from these wells during the late third and early fourth quarters.

Our gross operated DUC count in the Bakken has grown to approximately 165 wells and is expected to grow to approximately 190 gross operated DUCs at year end 2016. These DUCs represent a high-graded inventory with an average EUR of approximately 850,000 barrels of oil equivalent per well.

We view these DUCs as oil in the bank, and they represent the most cost-effective barrels we have in the company's inventory. On a cost-forward basis of $3 million to $3.5 million per well, these DUCs should deliver over 100% rate of return at $45 per barrel WTI and $2.50 per million cubic feet of gas.

We plan to continue to build our DUC inventory, and we'll begin completing DUCs as supply and demand rebounce and commodity prices improve. Now before I turn over to John, I would be remiss if I did not point out that our Bakken drilling team continues to achieve new milestones with technology and improved processes.

For example, it appears they recently set a new world record for the longest lateral drilled with one bit. The lateral portion of the well was almost 15,400 feet long and was drilled in five days.

The team also set a new company record for drilling a Bakken 2-mile lateral going from spud to TD in just 9.4 days. The 2-mile lateral portion of the well was drilled in an astounding 2.6 days.

These continued improvements in the Bakken team – with these continued improvements, the Bakken team is targeting a completed well cost of $6 million or an enhanced completed 2 mile lateral well down from $6.8 million at year-end 2015. Current cost is estimated at $6.2 million, and I bet they get there by year-end.

I'll close by complementing our employees, once again, for delivering such outstanding results in the second quarter of 2016. The teamwork, creativity and the effort that they put in is evident by our results and we considerably appreciate your commitment to excellence.

Now, I'll turn the call over to our CFO, John Hart. John?

Thank you, Jack. Good morning, everyone.

We're very pleased with another strong quarter. Revenue for the second quarter was $526 million, an increase of 30% over the first quarter of 2016.

EBITDAX was $528 million, an increase of 68% over the first quarter, benefited from a $97 million gain on the sale of our Wyoming leasehold that we completed in April. Continental reported a net loss of $119 million, or $0.32 per share for the second quarter.

Adjusted to exclude impairments, non-cash gains and losses on derivatives and gains and losses on asset sales, the net loss was $66 million, or $0.18 per diluted share. One of the second quarter's most significant achievements was the continued positive trend in operating efficiency, reflecting our lean and focused approach to operations.

Second quarter production expense was $3.72 per Boe, down from $3.76 per Boe in the first quarter of 2016. Second quarter G&A per Boe, excluding non-cash equity compensation, was $1.22 per Boe, slightly higher than the first quarter.

A very admirable result. Total cash cost as calculated on our slide deck, including interest, was $11.1 per Boe in the second quarter, up $0.81 from the first quarter of 2016, this primarily reflected the fact that our production started to roll over last quarter as we've been expecting for some time.

The key takeaway is that Continental's low operating cost in the second quarter 2016 continued to set the bar among peers. Just one example, on an absolute basis, total production expense actually declined 6% from the first quarter to the second quarter, from $78.6 million down to $74.1 million.

Our efficiency provides a strong competitive advantage for Continental today and moving forward. Changes in our 2016 outlook include the following: an increase in production guidance to a range of 210,000 Boe per day to 220,000 Boe per day, higher by 5,000 per day, reflecting strong results from our new STACK wells and enhanced completions overall.

We expect to exit the year with production in a range of 195,000 Boe per day to 205,000 Boe per day. Next, production expense guidance decreased to a range of $3.75 to $4.25 per Boe in comparison to the prior guidance of $4.25 to $4.75.

Cash G&A also decreased, going to a range of $1.20 to $1.60 per Boe from the previous range of $1.25 to $1.75. And finally, we've reduced the top end of our guidance range for oil differentials.

The second quarter oil differential was $7.21 per barrel, down $0.57 from the first quarter and towards the bottom of our guidance range of $7 to $9. For the first half of 2016, our oil differential was $7.51 per barrel.

We expect this trend to continue given additional pipeline capacity coming on line in the fourth quarter. Consequently, we brought down the top end of our differential guidance range to $8, so now $7 to $8 for our new guidance, recognizing that rail pipeline exchanges couldn't affect the second half as well.

Continental's complete 2016 guidance can be found in our Investor Presentation posted on the website, and also in yesterday's earnings press release. Now, let's discuss CapEx.

Capital expenditures, including acquisitions, totaled $219 million for the second quarter of 2016, bringing the year-to-date total to $544 million. Both amounts are consistent with our expectations and internal budget for the first half of the year.

We remain focused on balancing, spending within cash flow, and we are cash flow-neutral at an average WTI price of $37 for the year. Year-to-date through June 30, WTI averaged $39.60.

While we have witnessed significant price volatility so far this year, we are pleased that our focus on capital discipline and cost efficiency has enabled Continental to reduce long-term debt. Overall, debt peaked in the first quarter at $7.2 billion due to low oil prices in January and February.

As of July 31, we have reduced total debt by $100 million from that peak. Our liquidity position is strong.

We have no near-term debt maturities. And at the end of June, we had $885 million of borrowings against our credit facility.

At the end of July, the revolver balance had decreased to $820 million, reflecting improved cash flow. Obviously, there is considerable debate right now in terms of the commodity outlook for the second half 2016 and for 2017.

Fortunately for our shareholders, Continental is very well-positioned to manage through any reasonable price environment with best-in-class assets and efficient operations. In terms of our 2017 outlook, we currently have plans to disclose formal 2017 guidance late in the fourth quarter of 2016 or early in 2017 which is consistent with our approach last year.

In summary, let me reiterate how pleased we are with our second quarter 2016 results, and the stellar performance of Continental's operating and support teams. We have again strengthened our balance sheet, increased production guidance, and decreased operating expenses, further solidifying our position as one of the lowest cost producers in the onshore E&P space.

Our focus remains on spending discipline, and execution that will generate value for Continental, and our shareholders. Now, I'd like to turn the call back over to Harold.

In closing this morning, I'd like to review two very important questions with you concerning Continental over the past 24 months. What have we not done and conversely, what have we done?

First of all, we have not diluted our shareholders with equity offerings. We have not had across the board layoffs at Continental, we have not divested core assets.

What have we done? We maintained Continental's culture as an active exploration entity throughout this downturn.

We've kept our technical teams together in preparation for a market rebound. We've grown and established new assets in STACK, SCOOP and the Bakken.

Although we've greatly reduced our activity, we've remained very active as the number one driller onshore United States. Finally, through our drilling activities, we've continued to gain knowledge and technical expertise throughout all of our teams that positions Continental for strong profitable growth in the future.

And with that, I'll turn back to the operator for questions.

Good morning, guys, and congrats on another good quarter. A couple of questions for you, the production mix is getting gassy and I understand that you're not completing Bakken wells.

But maybe, John, are these levels kind of that 60% to 62%? Is that what we should average this year on the oil side?

Yeah, we're still in that same range. Obviously, we haven't been completing Bakken.

We will have a few incremental Bakken completions that we discussed for R&D. I think the key to remember is part of that is driven by the high productivity of what we're seeing in STACK and SCOOP.

These are huge wells. So they do have some gas volumes with them, but they've got significant oil volumes as well and it's a very rich gas.

So from an economic standpoint, they're very high rate of return, strong projects for us.

Okay. I was looking through my notes and I guess you all had about 10,000 barrels shut in as you all talked about last quarter on the call.

Did you all bring that back in online in the second quarter?

Yes. This is Gary Gould.

We continue to have about 10,000 to 12,000 net Boe per day shut-in. However, the mix has changed.

What we talked about last quarter was that we had 80% of that was gas that we shut-in. And so what we have now is that gas is back online at a price that's about $1 higher.

Currently the production that we have curtailed is oil production due to lower prices and that's all baked into our production guidance which again we have changed to be another 5,000 Boe per day higher. And so, very positive results from all of that.

That was helpful. Thank you.

And then one more, on the Northwest Cana, I guess, that one well you all highlighted was kind of eye opening. Is that a one-off well, or did you all do anything different.

Can you maybe elaborate there?

This is Glen Brown. Actually, we have really repeatable results in that part of our play for the Woodford system.

And it's just an example of the kind of results that we've been getting by improved targeting and enhanced completions throughout that entire program.

So, this was driven more by just more sands, bigger fracs?

More sand, bigger fracs, better performance, drilling and targeting and getting into the right part of the reservoir, yes.

And, Brian, this is Jack.

And two-mile laterals.

We just put that in there to give a little flavor of what's going on in Northwest Cana. We don't talk about it a lot.

In the Woodford, we haven't put out a lot of those IPs recently (32:35). And so, we just thought we'd add a little color with what's happening there.

No. Appreciate it.

That's not something we look at every day, so thank you. Thanks, guys.

I would remind you of the carried economics that we have in that section. We have a partner in our JV, and we have leveraged 50%.

We only pay 25%. Of course, our rate of return in that play is even better than it looks.

Thank you. Good morning.

Good morning, Brian.

Good morning, Brian.

I wanted to ask you on your strategy for how you're thinking about the learnings from the Yocum well compared to the Boden well. And so, one part of the question is are the rates of return that you're seeing in this dry gas portion of the play competitive enough for you to allocate capital to drilling the dry gas window, and then B, or B, would you use this knowledge to try to isolate more Boden-type wells, drill those, and how repeatable is this?

This is Jack, Brian. The Yocum well, as far as its performance, it's an excellent gas producer.

As you could see by the results we told you, it started to produce 1.1 Bcf after being put on line for a short period of time here. And as far as economics are concerned, at $2.50, we're easily in that 25% rate of return, and at $3, we're over 30% easy.

So it competes well with our other plays. But the purpose of drilling the Yocum well was just to test some geologic concepts.

As we said, we're expanding known productive footprint of this play, and we're looking to just basically substantiate our geologic model in here. And so this test was specifically defined and designed to test this downturn side.

And so what it tells us is that we've got about 2% of our acreage on that East side that's maybe a little more gassy now. But on the West side of the fault, our current model is holding very strong, and that's what we kind of suspected going into this.

And so, as you noticed, we had, what, 30% of our acreage in the play we said was in the oil window. Last call, actually really since we've been in the play, is kind of was our estimate.

And now, with the additional leasing and with the additional information we've generated, we now say about 40% of our 183,000 net acres is more in the oil window. These results are just part of our process of evaluating the play and really doesn't change our perspective at all, it just helps validate it.

Thanks. And my follow-up is also on the STACK area.

Can you talk a bit more on your thoughts on the Osage zone and plans for testing that?

Well, the Osage, we recognize as being under all of our acreage, and we as other plays – people on the play have commented, we believe that it is very prospective, and it's something that we are going to get to in a proper development.

Yeah. Brian, we see that as part of the whole petroleum system here, and we know that it contains oil.

And where we're focusing right now is more on the more Meramec-dominated area, and we will, with time, move more into the more Osage-dominated area.

Got it. Is that more likely for 2017 or even beyond 2017?

Yeah, I would think so. It's not going to be this year.

I mean, we've got a lot we still need to assess here. We've got a big, big area here that we need to get a handle on just from a Meramec standpoint alone, and densities and a lot of things.

A lot of questions need to be answered. And we'll move in that direction, yeah, 2017 and beyond.

Thank you.

Good afternoon, guys.

Hey, John.

Good afternoon, John.

Just following up on Brian's question. So now that you've updated the STACK with kind of the 40% now oil window, 40% condensate, 20% gas.

Should we think about it going forward that even as we get additional wells, those numbers probably at this point now don't change that meaningfully, like you have maybe some movements on the margin, but you don't probably have big changes in that kind of mix?

I think that's a fair statement right now, but we have a lot of territory to the west and south of us that we haven't fully evaluated yet. But based on all the information we have right now, we feel the numbers we're representing right now are, I guess, our best assessment of our hydrocarbon content of our acreage right now.

Remember, we expect to exit the year with 190 DUCs in the Bakken, averaging 850,000 EUR. With that, you can obviously imply an IP, and to Jack's earlier comment, we go back to work in the Bakken, we can certainly bring oil production back very rapidly.

I guess I was just referring to just the makeup of the STACK, just the fact that you went from a 30% to now 40% oil window. I guess, just going forward, thinking that that probably doesn't have big changes.

I think that's a fair statement, but I want to have the caveat that we still need to get more well information as we go West. But I think that we feel comfortable with what we're representing right now, and we'll see.

That's helpful. And then just one follow-up.

Is there any specific reason why the Bernhardt, the density pilot, that's a shorter lateral length than I'm typically used to seeing from you all and obviously relative to the other density pilots? Just anything specific on the reasoning there?

It came down to ownership, and we would have drilled two-mile laterals there if we could, but our ownership really required that we just do one mile.

We've been fortunate through this play that we've drilled about 95% two-mile laterals. This was just one isolated section out there by itself.

So, that's the only reason for it.

Yeah. When you look at it, I mean, we're definitely – as far as two-mile laterals are concerned, we're drilling those everywhere we can.

In the Southern region, we believe, which includes our STACK area and SCOOP, about 75% of our drilling currently and going forward will be 9,800-foot laterals. And in the North, up in the Bakken, it's 95% or more, probably 100%.

So we're big believers in 2-mile plus laterals. We definitely see the economic benefit from that.

So we've been down that path a long time ago as far as whether or not 2-mile laterals are worth it, and we definitely know that they are.

Thanks, everybody. Well done.

Thank you, John.

Thank you, John.

Yeah. Maybe I missed this.

What is the derisked acreage in STACK now? Is it still 100 or more than that?

In STACK, there's two levels of derisking. Again, I think we talked about this last quarter.

And there's the geologic derisking, and we have it geologically derisked from subsurface control. We have several hundred well penetrations out here, so we have a good handle on the distribution of the reservoirs.

The big question is just what the hydrocarbon content and deliverability. And so right now, I had mentioned that we had about 300 square miles that we feel that have been derisked in the play in this last year as we move over into the over-pressured window.

And that's where we've – each of the – that pretty much sums up say the townships where we've actually drilled, have producers and have comfort with what kind of production we could expect. So we're going to continue to step out and derisk.

But right now, I think it's – I don't know, I would say maybe 50% is derisked.

With production.

Yeah. With production.

And geologically like Jack says we've got penetration through the entire area.

Yeah.

Subash, if I could add to the geologic derisking, in our Yocum area, you've all seen our block diagram there. One thing I wanted to emphasize is that we have 3D seismic over 75% of our acreage.

We have over 500 well-controlled points out here. And this fault that we were testing the down-thrown side of, is a one-off.

There's only one of them out here with 300 feet or greater throws, goes up to 500 feet of throw. It's a true anomaly.

So this is not something that you would expect to see breaking up phase boundaries going forward, and it's a relatively structurally benign area.

Right. So will you drill further south, test further south of the Yocum?

We don't have much acreage, really, south of the Yocum. If you take a look at our map, you can see it's pretty scattered.

And so bulk of our drilling is – I mean, really, just bulk of our acreage is just west of that fault.

We've said before that our acreage is ideally situated for the quality of the Meramec reservoir. Let's just leave it at that.

Okay. And final one from me, the HBP, if I heard you correctly, so 60% of STACK is HBP, and I think you've got a big head start because you had legacy acreage that was already HBP'd.

And how do you think about the progression of that in year-end 2017, year-end 2018 at the current rig pace?

Yeah. We have expirations going into 2021.

As I said before, we have built-in renewal language, built-in top lease protections. Nothing expires in any of our core areas.

Okay. So in other words, there's no – really if prices warranted, you could reduce activity and not jeopardize your acreage position?

Yes, sir. That's correct.

Okay. Thank you.

Thank you, Subash.

Yeah. Good morning.

Thanks so much for taking the question. First one is more of a holistic question around production growth into next year.

You've done a great job maintaining this year volumes with much lower CapEx. Obviously you've got DUCs and efficiency gains into 2017, and then you said you could add rigs above $60.

But I'm just trying to think about what sort of production growth you'd be comfortable with in 2017? And then, as you got to $60, what's the upside scope?

I think, the way you answer that where you get the variability in process is a key component. We certainly have the assets, and long-term decades of assets.

We want to preserve that value. As we said earlier, we're pinching back our production a bit right now to preserve it for higher commodity prices.

So we're not inclined to grow in the current environment. Looking into 2017, we didn't give the day, but we've previously given maintenance capital numbers.

If we were to say wanting to hold flat at 195-ish range, the low end of our exit rate guidance, that'd be somewhere in the $900 million to $1 billion, $1.1 billion of CapEx. That's just maintenance cap.

We'll then take into account, setting up for outlying years or so where the commodity price is. But that tells you that at a relatively low level of CapEx we can hold relatively flat.

As commodity prices recover, we'll start to look to completing the DUCs in the Bakken and bringing on incremental production, moving up to $60 as you indicated in your question there. $60, we would certainly start looking that we would be working off the DUCs in the Bakken and we would be bringing on some incremental production and growth just from that.

And with our rigs, we certainly have a lot of efficiency there already. So, I don't know that we would need to add any rigs because we're processing well, but you're starting to move into a price environment where you could consider things of that nature as well.

And then a specific question on the STACK. I mean, obviously, take Verona.

It's in a different pressure regime then you go down to Boden. Just wondering if the well costs that you've given change as you go Southwest in the play as well as the oil cut?

Yeah, this is Pat Bent. And I do think that based on your position in the pipe as you move West, and Southwest, you'd have higher pressure, and that pressure results in higher well cost.

So you see some very low cost. As we look at the Ludwig that we announced on the density test where we've reduced our cycle time by 44% over the year-end 2015 numbers, reduced our cost by 28%.

So, that's on the Northwestern, and then we anticipate seeing similar type gains as we move to the South and to the West.

But say your $9 million well cost, I mean, the plus/minus around that average, how much extra is it down to Southwest versus up in the Northeast, how much?

An incremental $1 million to $1.5 million based on depth and pressure. And there's quite a bit of difference in depth, I think from Northwestern portion of play to the South – Northeast portion to the Southwestern is almost 4,000 vertical feet.

This is Gary Gould, and I would add that on the production side, as we move to the Southwest, we have higher pressures and higher production rates, and we see production rates that approach a 3 times factor as we move into the overpressured area compared to the lower-pressured area. So that more than pays for the small incremental cost.

Thank you.

Thanks. Up in the Bakken, if I'm not mistaken, the estimated $3 million to $3.5 million completion cost was based on wells you completed quite a while ago.

If that's the case or even if it's not, are those numbers something you feel are conservative and you could beat? And if so, even with oil having commoditized the rate of return, if you can complete these for, say, less than $3 million, gets even more compelling than it already is.

So can you discuss that a little bit?

Yes. This is Gary Gould.

And that $3.5 million estimate is a recent current estimate. And so that is what we expect going forward.

It's for the completion, as well as for the equipping cost going forward. So there's a little bit of facilities in that besides the completion side.

As shown, it provides over 100% rate of return just looking money forward.

Okay. And then one housekeeping question.

The 29,500 non-strategic SCOOP acreage you sold, does that need to be backed out of the – I believe, it's 970,000 net reservoir acres that you're showing total in Oklahoma in the SCOOP and STACK, or is that already taken out?

This is Steve Owen. Yes, sir.

Our net reservoir acres prior to the sale were 970,000 acres. Post sale, it will be 926,000 net reservoir acres.

Okay. And then just flipping that around a little bit.

There's obviously been a lot of transaction, including several big ones over the last seven months, eight months in the play. Just your general thoughts on possibly adding to your position, or I got to think you look at everything that comes for sale there, so just your general M&A thoughts in Oklahoma.

Yes. We're always looking to acquire additional acreage and build acreage position.

We've been doing that consistently and our teams have done very good job by doing that. We've added 12,000 some acreages over the last quarter.

Yeah. And obviously with the position we've got out there and the low cost of entry that we have, we're really pleased with the valuations that we're seeing, that are occurring out there.

I mean, people obviously are very interested in this play and paying some very high dollars to make entry and build their positions. And so you're asking what maybe our appetite is for that and it's really hard to go out and pay retail I always say when we are actually in wholesale.

And so although we look at all these, it's hard for us to really compete and the depth of our inventory both here in STACK and corporate-wide is so deep and such high quality. I mean, I've been here for 24 years now just as of last month and this company has never had a larger or better quality inventory than it does today.

And so if we don't buy like any – grow any at all up in here in STACK say for instance, we have no trouble having inventory to grow.

Great. All right.

Terrific. Thanks, everyone.

Thank you.

Thank you, Steve.

Hi, everyone.

Good morning.

John, I want to just go back to your initial thoughts on the call talking about potential for volatility and commodity prices and the plan to spend within cash flow. Just wanted to get some more detail on what your primary means of toggling your spend rate quarter-to-quarter as finally prices move around would be, that's rigs or completions or just what do you think that would be?

This is John. If you look at us through the year, we obviously came into the year higher and we've consistently come down throughout the year which make the third and fourth quarter the level of spent to be lower than it has been.

So that trend continues. The rigs that we have are under contract.

We obviously look at the pace of completions and what we're doing there. We've done some of that as we've pinched back on that.

Quite frankly, we've seen uplifts from the wells we have completed. So we've seen higher revenues coming in from that.

The big thing is just the efficiencies that we're continuing to see across the board. We had a pretty rich script, if you will, with a lot of the efficiencies that we talked about, the drill times, the improvement in the Bakken, what we've seen in the South and in the SCOOP.

Those are continuing to come forward. Jack reference the pads that we're moving to in STACK.

Pad drilling in the Bakken is your analogy for that. As you know, as we shift from single wells to pad drilling, we've typically seen 30% to 40% improvement in costs and we've seen that in the Bakken.

We saw that in SCOOP and they're continuing to. And you know I think that's a big catalyst and obviously we've got a greater mix of those going forward in the South than what we've had historically.

So, continued improvements, continued management of what we're doing in efficiencies and a greater shift to a pad drilling and then just the productivity of the wells, we're getting more for less.

Yeah. Drew, this is Jack.

And that's why I stressed at the beginning of my portion of the call was just the fact that the capital efficiency that we've gained here in the last 18 months. We've really reset the bar for the company, and it's a combination of everything we've talked about.

It's lower drilling costs, lower operating costs and the upgrade in the inventory that we're drilling. We moved back into the core of the Bakken.

So, we went from 550 MBoe equivalent average to 900 Mboe this year. And so that's a significant change in the basically the barrels you find per dollar.

And when you put in the high performance of the STACK area and look at our lower cost, I mean, what we're seeing is that our capital efficiency truly – I mean, it's up 133% over where it was in 2014. So, you can look in the rearview mirror, the project where we're going, and we can't do a heck of a lot more with lot less.

Yeah. The results are excellent, and I think it's a testament of the quality of the team you have there at Continental.

I was kind of thinking higher level in terms of, yes, you've executed on cost and technology and productivity. I think by and large people feel like you have fantastic assets.

But you talked about this plan to get debt to a lower level where you have a really peer-leading balance sheet. So I was curious, I think you have some of those drilling rig contracts rolling off as we get into 2017, as you commit to that plan to spend the cash flow and work debt down over time.

Yes, I'd like to point out one thing, Drew, and this has played an important part here. We came into the year really front-loaded with non-op budget, non-op cost from other operators.

This is a big portion of our ownership is selling off some of these areas. And anyway, that was front-loaded, pretty high that, but we've seen that drastically reduce throughout the year.

So that just plays one part. And I'm going to let Gary Gould comment on rigs.

Real quickly on the rigs. I mean, you've seen what our year-end target is.

We've described that in our slides. When you think forward to next year.

Next year, over half our rigs come off a long-term rig contract. And if you look at current market prices are about $10,000 per day less.

And so for some of our 40-day wells, that'd be another $400,000. So there are some additional capital efficiencies that we have clear eyesight to into 2017 even beyond what our year-end targets are.

Drew, this is John. Let me give you just a couple of high levels.

You referenced on the debt coming down. Well, one, we announced today a $281 million sale.

Those proceeds prospectively will go to debt reduction once we close that. That'll be some time in the early fourth quarter likely.

So, those are proceeds that go to that. Additionally, we gave you an indication of the July debt balance.

We did that for a reason. You saw that from June 30 to July 31, the revolver balance went down by $65 million.

That was up – that was positive pure operating cash flow. So, as we're above our breakeven point, so we expect to generate positive cash flow through the balance of the year.

We've got one announced transaction that'll bring in cash that will pay down debt. And as we've indicated, there are other assets that are great assets, very high quality that was 20 years to 30 years of inventory.

There's some things that are longer out in our portfolio that we could part with to further reduce debt. We'd like to get back down around to the target or the level of debt we were before this cycle began a couple of years ago.

So, Harold referenced kind of a $6 billion target. And we certainly have the ability to do that while still preserving our strong growth rate going forward with the quality of our assets.

This is Gary Gould. I might add one more thing.

In parallel with the rigs for next year, that's going to free up additional capital that if we chose, we could apply to our DUCs, which are much lower capital and provides additional cash flow from those and so instead of growing our DUC inventory this year from 170 wells to approximately 240 wells next year, a larger percentage of our capital will be applied to completions, which generates more cash flow.

Yeah.

Thanks for the color.

Thank you.

Thanks. Good morning.

I think it's still morning, everybody. Guys, if I could ask the de-risking question a little differently?

1,200 locations is what you have defined in the presentation. What percentage of your acreage, Jack, have you assumed that's over at this point?

That's going to represent, I'm going to say, about two-thirds of our acreage.

And the spacing assumption is on there, but that doesn't assume the successful spacing test then I assume?

We'd be looking at 12 wells per unit. So that'd be four in the Woodford, four and two Meramec zones.

And your downspacing test assumes what?

Say it again?

The downspacing test takes it to what?

Well, we're testing that right now. Our downspacings right now, the densest we're going to is five right now.

Some folks are testing upwards of eight wells per zone. And so the jury is out as to what is the proper spacing in here, and it's going to vary between area and obviously reservoir thickness and all that.

But just as a general rule of thumb right now, we're saying – we think our opinion is right now we can get at least four wells per zone in each of the Meramec zones, and we have three Meramec zones we're targeting. And based on the distribution, we think we'll generally have two of the three zones developed.

And then we also have a Woodford zone below, and we think we'd put four wells in each of those. So four times the three zones get you 12 wells.

Got it. Thank you.

So my follow-up question then is, at what point – I realize you're still only 60% HBP and you are adding acreage and so on, but at what point do you think at least a portion of the field would move towards full-field development? And when that happens, what does pad drilling do to your $9 million well cost?

Well, from a cost standpoint, we expect that we'll continue to go down as we get more efficient, and pad drilling, we just see substantial efficiency gains and cost reductions when we move to pads and just as you can see with the Ludwig. But as far as how quickly could we move to the full-field development, right now we've got several other density pilots or projects that we have in the queue right now.

And we're right now finalizing plans and getting directions on how we want to go. Bulk of them I'd say right now are in the over-pressured oil window, but we have one that we're looking at doing as we've mentioned I think previously in the condensate window as well.

Got it, thanks. Maybe just one final one if I could add it.

The Frankie Jo and Madeline, relatively close, I guess, but a big difference in oil cut. Could you at least give us some idea as to how you feel?

Do you think that trend continues to accelerate towards a more – a higher gas cut as you move further to the west?

Well, as you move deeper into the basin, we do expect to see a higher GOR, but at this point, there's not a substantial difference between the two, and pretty much in line with expectations.

Thanks, fellows.

Thanks, Doug.

Thank you.

Thanks, Doug.

Thanks for getting me in, guys. Say just looking at that slide 12, Jack, you've got obviously a lot of rigs down in that very Southwest corner in Custer.

Wondering your thoughts there about Woodford potential in that area as well as the extension of Meramec?

Okay, let me get to slide 12 here. Excuse me.

Yes, just kind of referencing all those you have down in that corner.

Yeah. And what our thoughts about the Woodford?

Kind of the Woodford potential in that area as well as the extension of the Meramec that, as I keep going further Southwest there.

You bet. You bet.

Well, Meramec continues on down on the Southwest trajectory right out – continues on past our acreage there. And as far as Woodford's concerned, our Yocum well is right down in that particular area.

But we have, as you see, we've got several wells in there that we've drilled and we're testing for the Meramec. And so we're very optimistic and positive about it.

I mean, the reservoir gets – Glen can add some more color on this, but the reservoir quality improves and the pressures are just – this is where we have some of the highest pressures.

Yeah. This is Glen Brown.

I'll jump in. The rigs that you're seeing there are targeting the Woodford.

That's part of our JV I mentioned earlier. And for every well of those – the Woodford is obviously deeper than the Meramec/Osage targets.

So every time we drill a well out there, we get a log, we get shows, we get mud logs, we collect data. And we're building our database as we're also HBP-ing our JV acreage.

And so it's a wealth of knowledge that we're building out there, and we're using all that information to go into our predictability of our phase boundaries we've been discussing during this call.

Yeah. And I misspoke previously.

I said Yocum well. I probably confused you when I said the Yocum is down in that area.

All right.

I was thinking about the Lacretia.

Okay.

Because it's in our Northwest Cana area. And so it's in that area that you're talking about, and that shows you how prolific the Woodford can be.

And then, Jack, on the Yocum, I did have one last question on that. It looks like the throw of that fault is about 400 or 500 feet, but then it looks like, if you look at the depth trends, it looks like you're getting deeper.

So should we think about the gas window as being anywhere – 500 feet deeper than that? I guess what I'm getting at, it looks like the Boden is about 11,000 feet, Yocum is about 11,500 feet.

So does that mean anything below the 11,000 is conde or below 12,000 is gas? Or how should I think about that?

We're not ready to go there at all. I mean our geologic model is a little bit more involved than just depth equals GOR.

And so – anyway, so I think we'll let that play out.

Very good. Thank you.

Okay.

Thank you.

Yes. Just a quick question.

When do you plan on bringing back the curtailed oil production?

I can answer that. I mean it's going to depend on oil prices because we don't expect the oil prices to stay low for very long.

So we expect it to come back on before the end of the year.

Okay. And on the – how much time is – or how many – when was the – will the carry in Northwest Cana be up?

Just wondering how much longer you will be drilling there so actively.

2.5 years will remain on the carry. And it's about a $50 million a year carry.

And I think in the last two years, it accelerates to $60 million.

Yeah.

Okay. Thank you.

Thank you. Thanks, Marshall.

Good afternoon, guys.

Good afternoon.

Good afternoon.

Regarding your 3D seismic in the STACK, where are you generally short seismic coverage?

Well, there's a few patchy areas that are kind of in the central part of our acreage block that we're currently permitting and getting ready to in-fill. But it's a very – like I said, we have over 75% of it coverage.

Now if I include my 2D seismic database, I'm nearly 100% covered over – with reasonable geological control. So, in terms of 100% 3D, we'll be there by this time next year.

Okay. Fantastic.

And then, moving over to the SCOOP oil. So with the type curve revision that you guys have announced, could you comment on what specific completion design is comprehended in the 1.3 million barrel type curve?

Yeah. Specifically, we see the most benefit right now from more sand.

We continue to see great results from using a fluid that's slickwater or hybrid fluid which is mostly slickwater. We continue to see great results from shorter stages.

We continue to experiment with cluster spacing and mesh size. But the biggest benefit we see right now has been volume of sand and so the enhanced completion is more than double the old completion in terms of pounds of sand per foot of lateral and that's a major contributor right now.

And was there a specific proppant per foot lateral that was based on that?

I would say that right now, we are testing from 1,500 to 2,500 or more pounds per foot and so that's the type of range that we can add for this enhanced completion EUR.

And last question from me, just looking at page 14, seeing the Blurton and the Ludwig next to each other in terms of what you guys are doing with the configuration there? Do you think the Middle Meramec is prospective in the Blurton pilot given its proximity to the Ludwig pilot?

Clearly, we don't see the middle developed as well as the upper and the lower there. And so we chose to go ahead and put our wellbores in the upper and the lower on the Blurton.

And if you noticed, too, up in the Blurton, we have a little bit different distance between wellbores, and that's really based on reservoir thickness and what we think what density we need to drain particular areas. So we're getting that specific on what we're doing here in these early tests so we can better understand what full field development looks like, because the Meramec will vary in thickness and does vary in thickness across here.

And in some areas, you can get much more dense, in others you can get less dense, and that's what we're looking for, is that optimum design given certain reservoir thicknesses.

I might add that what you're seeing there in terms of the pads is not necessarily what the full pad development looks like. Just look at the Ludwig.

We anticipate filling in Woodford wells in that later – in that particular pad at a later date. So sometimes we go out and we test individual things so that we don't see interference from other levels.

Right. No, that's a good point, Glen, because we do plan on including the Woodford in our full field development going forward.

We're just doing these tests between the Meramec and this one.

Thanks for the added color.

Certainly.

Thank you, Derrick.

Yeah. I have two quick questions.

Of the 27,000 acreage you've added in the play this year, could you give us a sense of how much of that acreage has been added in the oil window versus the condensate or gas window?

I'm going to say that it's fairly evenly distributed. I think it's a fair statement here.

So, I would say that the fact that we've seen the percent in the oil window increase is a combination of acreage and results.

Great. Thanks for that.

And then as we think about 2017, obviously understanding you're still connecting a lot of the dots in the STACK and a lot of appraisal and delineation drilling, would you view 2017 as – how do you think about the balance between moving into, call it, a development mode versus that appraisal angle?

Well, I think to appraise that properly, I think we're in a development mode out here. I mean, yeah, we see a little different results across the play, but we're anticipating those and we're in full development of this play here.

It's one of the best plays we've ever been in a company, and it's got outstanding results. And so we're in full development.

Yeah. The reason we can move into the development mode, like we're doing up there in the over-pressured oil window so quickly, is just the degree of subsurface control in here.

So often in plays, you got to go out there and you got to demonstrate the physical extent of the reservoirs and the location and the depth and all of that. And here, with the subsurface control that we have, all that's behind us.

And so that we're doing is just really – the whole play will develop at a more accelerated pace because of that knowledge.

Okay. And just one last final one.

It's just on the decision on the eight incremental Bakken wells to complete. What was the thinking around that?

This is Gary Gould. Our main thinking around that was we got a huge DUC inventory that we're going to be completing next year, and we want to continue to do some experimentation so that we understand what the most optimum completion is.

So we want to get some more technical information.

Fair enough. Thanks a lot, Gary.

Thanks again, everyone, for joining us today. We look forward to reporting another great quarter in early November including new density test results.

Thank you and have a great day.