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

Drew E. Venker - Morgan Stanley & Co.

LLC Subash Chandra - Guggenheim Securities LLC Brian Singer - Goldman Sachs & Co. Brian Michael Corales - Scotia Howard Weil Arun Jayaram - JPMorgan Securities LLC John A.

Freeman - Raymond James & Associates, Inc. Doug Leggate - Bank of America Merrill Lynch Derrick Whitfield - GMP Securities LLC Neal D.

Dingmann - SunTrust Robinson Humphrey, Inc. Mike Kelly - Seaport Global Securities LLC Pearce Hammond - Piper Jaffray & Co.

(Broker) Marshall Hampton Carver - Heikkinen Energy Advisors LLC Noel A. Parks - Ladenburg Thalmann & Co., Inc.

(Broker)

Thank you, Latoya. I would 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 will be other senior members of the executive team including, Jeff Hume, Vice Chairman of Strategic Initiatives; Pat Bent, Senior Vice President, Drilling; Glen Brown, Senior Vice President, Exploration; Gary Gould, Senior Vice President, Production and Resource Development; Steve Owen, Senior Vice President, Land; and Ramiro Rangel, Senior Vice President, Marketing.

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.

Also on the call, we will refer to certain non-GAAP financial measures. For a reconciliation of these to generally accepted accounting principles, please refer to the updated investor presentation that has been posted on our website at clr.com.

Now to begin this morning call, I'll turn the call over to Mr. Hamm.

Thank you, Warren, and good morning, everyone. On our last earnings call, I said we will discuss how all aspects of Continental's operations were staying at very high level well, stronger well results in STACK and SCOOP, faster drilling times in the Bakken, lower operating costs and lower completed well costs.

This quarter was no exception and continued the rock solid performance of our top tier assets and people. This is who Continental is, and we've proven it again.

Continental's results just keep getting better. We started the year off with record quarterly production of 230,800 Boe per day and raised our production guidance as a result.

We began managing production rates early in STACK and also in April within SCOOP to approximately 10,800 Boe per day they're drilling at this time to preserve the commodity for a better market and operational efficiency, due to the high flow rate capability and pressure of wells in STACK. The well results this quarter in our STACK were truly amazing.

The Foree, Bernhardt, and Quintle are just some of those. Jack will describe these wells in more detail in a few minutes.

Our Bakken, STACK, SCOOP, Springer and Woodford and Northwest Cana teams are doing exceptional work across the board. We see this downturn as an opportunity to get meaner, smarter and more effective in every aspect of the business.

Let's look at our first quarter accomplishments. Continental executed its strategy very early in 2016 and continues to do so.

We've aligned ourselves to lower prices over the past 18 months and are now operating on plan within our $920 million capital expenditures budget for the year, under which we expect to be cash flow neutral for the full year at an average $37 per barrel WTI. Based on the current strip, we project to be cash flow positive for the year and see further debt reduction.

From a cost perspective, this is a significant accomplishment which allows us to compete globally. We've also pioneered and captured new operating efficiencies in drilling and completions, maximizing the value of the top quartile assets.

Leading experts in investment community recognize these top quartile assets, the value of which continues to get better as recoveries go up and costs come down. We've seen early EUR uplifts of 15% to 45% in all plays: Bakken, SCOOP, STACK, and Northwest Cana and even stronger early production results.

Oil as a percentage of total production was 63% in the first quarter driven by enhanced completions in the Bakken last year that continued to outperform type curves. And we are not done.

We continue to increase profit loads per stage and experiment with fluids and other design parameters to find the optimal completion technique in each of our plays. Enhanced completions are working to improve economics throughout our leasehold.

This makes our leasehold positions even more valuable and as announced yesterday, we have increased our production growth guidance for the year with no change in CapEx. That is strong.

We're seeing outstanding results in terms of drilling efficiencies and lower completed well costs, and as a result, we're proud to announce we lowered the target – completed well costs in the STACK and the Bakken. Our results continue to validate our STACK position in the premier over-pressured portion of the play.

These wells are among the best performing wells I've been involved with in my entire career. Jack will go into more of the operational details in just a minute.

The STACK is going to be an essential contributor to Continental's long-term growth. Another aspect of Continental's performance – project performance actually focuses on what we did not do.

We didn't delude our shareholders by selling equity at the low point in the cycle. We didn't have company lay-offs, instead we kept our teams together and we maintained our culture of loyalty and trust, uplifting the morale and spirit of our people.

And finally, within (06:36) the best core assets. In fact, we grew them.

We preserved and built future shareholder value through them. Following through on our previously stated interest in selling non-core assets to reduce debt, we announced the sale of non-core non-producing leasehold in Wyoming for $110 million.

We sold 132,000 net acres in the Washakie Basin where we still retain 40,000 net acres. This is a prime example of bringing value forward from assets that had no proved reserves on the books and one that we were not receiving any value for, from the market.

We will continue to consider additional sales of a similar nature in the future. Now let's turn to the macro environment.

Since our late February call, oil prices did hit an inflection point responding to defining global supply and demand growth that is higher than most others expected. As supply and demand continue to align, oil prices started to climb back in the direction of realistic long-term values.

We expect more that the 40%-plus increase in oil prices over the past two months is the first of many steps we believe in the right direction. The U.S.

is once again a world energy leader and as world market rebalances, I believe U.S. producers can and will compete on a global basis.

The U.S. is positioned to meet the future, global energy demand growth with high quality assets and low cost of production.

Now, the U.S. producers are finally free to export oil and natural gas worldwide, producers can capitalize on the development of these play.

Specifically at Continental, with the best in class assets, our low cost of production and G&A and efficiency of gain, we have a strategic advantage and we can compete with producers anywhere in the world. In summary, let me just say this.

We're encouraged by our company's results and the improvement in the macro environment. We are looking for oil prices to continue strengthening through the remainder of the year.

With new data each month, more and more analysts and investors are gravitating toward a view of supply and demand rebalancing in the second half of 2016 rather than late 2017. In fact, many analysts are now predicting a shortfall in supply as early as late 2016.

If you recall, this is something we've been saying publicly since January based on the work of the research teams and the market is now getting on board. We are strengthening our balance sheet, preparing to start working down DUCs.

We will be disciplined and are poised to create tremendous shareholder value from this point. As the market rebalance, being a low-cost producer with some of the best assets in the onshore U.S., makes it fun once again to be in the oil business.

With that, I will turn it over to Jack.

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

As Harold mentioned, we have some pretty impressive operation results to share with you today. I will focus primarily on our results in STACK and SCOOP where our new and existing wells continue to meet and exceed our expectations.

This reflects both the quality of the reservoir rock underneath our acreage and the success we are having unlocking more hydrocarbons through enhanced completion technologies. I will begin my update with STACK and I want to remind everyone of three key points about STACK that are of critical importance to Continental and its shareholders.

Number one, STACK is totally incremental to Continental. Less than a year ago, we had no reserves or production on the books for the STACK, Meramec and Osage reservoirs.

We believe STACK could add as much as 25% to Continental's net unrisked resource potential at today's prices. Number 2, our cost of entry at STACK was minimal.

That's because the majority of our acreage was legacy acreage that was – and about 65% of it was HBP at the time we entered the play. And third, Continental controls approximately 171,000 net acres and what we consider to be the hardest STACK.

Approximately 95% of this acreage is located in the over-pressured window of STACK where some of the thickest and best Meramec reservoirs are developed. Over-pressuring is significant because it increases the recovery of hydrocarbons from the tighter reservoirs like Meramec, Osage and Woodford reservoirs.

Results to-date show, on average, wells in the over-pressured STACK produce at rates approximately three times higher than wells completed in a normally pressured window, on a normalized 9,800-foot lateral basis. As noted in our release, we completed three new wells of STACK including the Foree 1-18-7XH, the Bernhardt 1-13H and Quintle 1R-10-3XH, all are Meramec completions in the over-pressured oil window.

These wells were strategically located to demonstrate repeatability and to extend the known productive footprint of the play. Initial production rates from these new wells are in line with the previously reported wells, demonstrating good repeatability.

In fact, the Meramec is delivering some of best repeatability we've seen from any play this early in the development. The Foree is a step-out located 8 miles west of our Ludwig 1-22-15XH which was our first well in STACK.

The Foree was completed following 2,060 barrels of oil equivalent per day at 3.300 PSI flowing casing pressure through 69% of the production being oil. Bernhardt is another step out located halfway between the Ludwig and Foree and was completed flowing 1,046 barrels of oil equivalent per day at 2,145 PSI flowing casing pressure with 78% of the production being oil.

I should point out that the Foree is a 7,200-foot lateral and the Bernhardt is a 4,550-foot lateral. When normalized to a 9,800-foot lateral length, the Foree and Bernhardt wells are producing in line with our previously completed wells with laterals that were approximately 9.600-feet to 9.800-feet long.

The Quintle located directly north of our Ludwig well is in the flowback and early testing stage. It looks to be another strong producer and rates are still climbing.

Yesterday, when we filed the release, it was flow testing at 2,150 barrels of oil equivalent per day with 71% being oil. Today, the Quintle is producing 2,192 barrels of oil equivalent per day at 1,800 PSI flowing casing pressure with 74% of the oil being oil.

The Quintle is a 9,850-foot lateral. We currently have five additional Meramec wells in STACK that are in various stages of completion including four wells in the over-pressured oil window and one well in the over-pressured condensate window.

Needless to say, we're very pleased with the results we've seen in these new wells as they demonstrate repeatability and support our economic model for the overpressured oil window. On top of the exceptional well results, the STACK team reduced targeted well costs an additional 5% to $9.5 million, through drilling efficiencies that they achieved so far in the play.

Big part of this was our success in reducing Spud-to-TD times by 32% for Meramec wells in the overpressured oil window, going from an average of 44 days in 2015 to just 30 days of the first quarter. So, our current economic model projects that wells completed in the over-pressured oil window STACK deliver a 75% rate of return at a WTI price of $45 per barrel and $2.25 gas, assuming 1.7 million barrels of oil equipment recover more reserves and revised target well cost of $9.5 million.

As a reminder, our economic model is based on 14 wells that have been producing at least 110 days. A perspective of a couple wells in our economic model include our Ludwig 1-22-15XH and our Compton 1-2-35XH.

The Ludwig has produced approximately 250,000 barrels of oil equivalent in its first 270 days on production and is currently producing at a curtailed rate of 680 barrels of oil equivalent per day at approximately 1,600 PSI flowing tubing pressure with 72% of production being oil. The Compton has produced 153,000 barrels of oil equivalent in its first 118 days on production and is currently producing at a curtailed rate of 836 barrels of oil equivalent per day at 1,700 PSI flowing casing pressure, with 70% of the production being oil.

Bear in mind, we're not producing these wells at their maximum capacity due to the low commodity price. I should also mention that the Boden 1-15-10XH in the over-pressured condensate window has posted some impressive production figures as well.

It has produced approximately 240,000 barrels of oil equivalent per day in its first 150 days and is currently flowing at a curtailed rate of 1,268 barrels of oil equivalent per day at 4,700 PSI flowing casing pressure with 26% of the production being oil. To accelerate our understanding of the full potential of STACK, we've begun drilling the first of three density pilots we plan to initiate this year.

Our first density pilot is located in our Ludwig unit in the over-pressured oil window. This will be an eight-well Meramec density test, including our original Ludwig well and seven new wells.

Average lateral lengths will be approximately 9,800 feet. We will be developing what we identify as the upper and middle Meramec reservoirs with four wells in each reservoir spaced approximately 1,320 feet apart with wells in the middle Meramec offset 660 feet from wells in the upper Meramec.

We will also put one wellbore in the Woodford to further develop the Woodford reservoir and facilitate microseismic monitoring. We'll be acquiring a great deal of scientific data from the Ludwig density pilot, including advanced petrophysical logs and cores to better understand the Meramec reservoirs and microseismic data that will help optimize future completion designs.

We currently have four rigs drilling in the Ludwig density pilot and expect to have initial results in the fourth quarter of 2016. We have two additional density pilots planned for 2016 – one in the over-pressured condensate window and one in the oil window.

We'll keep you updated as plans materialize for these pilots. So a couple of final points for STACK are: one, production from STACK is on the rise, up 44% over the fourth quarter of 2015 to 11,127 barrels of oil equivalent per day; and, two, we increased our rig count in STACK from 10 to 11 by transferring one rig from SCOOP.

Six rigs are now targeting Meramec, and five rigs are targeting Woodford in the Northwest Cana JDA portion of STACK. Now, let's move on to SCOOP where we recently completed our fourth Woodford density project called the Newy, located six miles north and two miles west of our original Poteet Woodford density pilot.

The Newy was an eight-well density project with seven new wells and one legacy well. The seven new wells produced at a combined peak rate of 87 million cubic feet of gas and 3,928 barrels of oil per day or 18,475 barrels of oil equivalent per day with 21% oil.

This averages 2,639 barrels of oil equivalent per day, which is right in line with rates on a per well basis from our Poteet, Honeycutt and Vanarkel density projects showing remarkable repeatability. Like the prior density projects, wells in the Newy density project were placed in both the upper and lower Woodford with four wells in the upper Woodford and four wells in the lower Woodford spaced approximately 1,320 feet apart with wells in the lower half offset 660 feet from wells in the upper half.

The Woodford reservoir and the Newy unit is approximately 260-foot thick, and average lateral length was approximately 9,850 feet. For perspective, the Poteet density project has produced a total of 381,000 barrels of oil and 28 Bcf or just over 5 million barrels of oil equivalent in approximately 450 days.

The Poteet was producing 45 million cubic feet of gas and 330 barrels of oil a day at last report. In the last quarter, we increased the E1 (19:23) model for our Woodford condensate wells by 15% to 2 million barrels equivalent per well.

This was based on the initial 90 days to 180 days performance of 15 strategically placed wells with enhanced completions. We have continued to monitor the performance of these wells and added another 5% to the 90-day and 180-day rates.

So our enhanced completed dense condensate wells are now producing at rates 35% to 40% higher than their offsets. And our technical team said they are not done yet and believe there is additional upside to be had through further enhancements to our completions in SCOOP and all of our plays for that matter.

I say this to point out that our teams are diligently testing various proppant volumes, proppant sizes and stage lengths to ascertain the optimum completion design in all of our plays. In the upside to the enhanced completions is that by increasing the performance of EUR of our wells, these enhanced completions are also expanding the footprint of our core acreage positions.

A couple of notable enhanced completions in SCOOP Woodford condensate this quarter include the Gretta 1-17-20XH in Carter County and the Sandy 1-29-32XH in Grady County. The Gretta is a significant step out located 37 miles south of the Newy density project, and it flowed at an initial production rate of 977 barrels of oil and 9.4 million cubic feet of gas a day or 2,546 barrels of oil equivalent a day from a 6,600-foot lateral.

The Sandy flowed at an initial production rate of 440 barrels of oil and 12.2 million cubic feet of natural gas or 2,481 barrels of oil equivalent per day from a 9,900-foot lateral. Both wells have been producing less than 90 days, but the early production indicates these wells are producing above legacy offset wells.

The average completed well costs for our operated Woodford wells, is currently $10 million, which includes an incremental $400,000 for the cost of enhanced completions. We expect to achieve a targeted well cost of $9.6 million by year end 2016.

At a cost of $9.6 million and an EUR of 2 million barrels equivalent, a typical SCOOP condensate well would generate a 30% rate of return based on $45 per barrel WTI and $2.25 per Mcf gas. Moving north to the Bakken, I want to quickly highlight a couple of points.

First, our Bakken team continued to focus on efficiencies, and they recently set a new internal record of 11.2 days Spud-to-TD for standard two-mile well. When you combine these efficiencies with the additional reductions in completion costs being realized, our cost for enhanced completed two-mile laterals now stands at $6.3 million, down 7% from year-end 2015's estimate of $6.8 million and the team is targeting $6 million by year end 2016.

The second point I want to make is that while our costs continued to come down, enhanced completions continued to improve our Bakken well performance. The average EUR for the Bakken wells we plan to drill in 2016 is increased to a targeted average of 900 MBoe equivalent per well versus 800 MBoe equivalent per well in 2015.

This reflects the results from our enhanced completions and the additional high grading of our inventory for 2016. We are currently deferring completions on most of the Bakken wells drilled in 2016, and as budgeted, we expect to have an inventory of approximately 195 Bakken DUCs, drilled and uncompleted wells at year-end 2016, an impressive average of EUR of 850 MBoe equivalent per well.

At a projected cost forward of $3.5 million to complete a DUC, the incremental cost forward rates of return are over 100% at $45 WTI. Needless to say, we have some very cost-efficient barrels to be harvested in the future from our inventory of DUCs.

We also have 10 years of drilling inventory average 800 MBoe equivalent per well, assuming 15 operated rigs. So the final thought, I want to thank our employees for their hard work and dedication to reducing cost, maximizing value and adding yet another significant asset to our portfolio in STACK.

Your ingenuity along with our top-tier assets enables Continental to deliver recycled ratios and cash margins that are among the best in the industry and positions Continental as a leader in the industry. So with that, I will turn it over to John Hart, our CFO.

Thank you, Jack. Good morning, everyone.

I want to first discuss our updated production guidance. Then I will touch on the usual financial items, our currently liquidity position and finally provide a bit of cover on 2017.

As both Harold and Jack mentioned the results from our enhanced completions have been outstanding and continue to overachieve. First quarter production came in at a record 230,800 Boe per day.

Due to the strong production and our line of sight into the rest of the year, we updated our production guidance for 2016 to average between 205,000 to 215,000 Boe per day versus the original guidance of 200,000 per day, reflecting strong performance across our portfolio, particularly with the enhanced completion Bakken wells. Slide 30, in our slide deck online, shows our Bakken enhanced completions are generating 45% to 60% higher 180-day production rates when compared to our historical completions.

These 45% to 60% higher 180-day rates are 10% higher than the 90-day rates reported last quarter, which show the strength of our sustained production from the enhanced completions. We also now expect to exit 2016 at a higher exit rate with production between 190,000 and 200,000 Boe per day.

Production should decline gradually quarter-to-quarter for the remainder of this year to reach this exit rate. Our playing capital spend remains unchanged at approximately $920 million.

Additionally we are seeing exceptional results in cost measures, particularly LOE and G&A expenses. Currently, we see each of these at the tight side of our guidance or better.

We will review these at midyear and adjust guidance if appropriate. Revenue for the first quarter was $404 million and EBITDAX was $315 million, both reflecting weakening commodity prices over the first two months of the year.

Continental reported a net loss of $198 million or $0.54 per share for the first quarter 2016. Adjusted to exclude impairments, non-cash gains and losses on derivatives and gains and losses on the asset sales, the net loss was $150 million or $0.41 per diluted share.

For the first quarter 2016, oil production was 63% of total production. Previously we mentioned oil percentage of total production was expected to average approximately 60% in 2016.

Based on the strong results of our Bakken enhanced completions, we now expect higher oil production averaging 61% for the year. A good example of how we can scale our oil percentage back up.

Non-acquisition capital expenditures for the first quarter were $320 million, essentially in line with capital guidance we gave for the first quarter in January of approximately $300 million. Approximately $30 million of our $320 million capital spend was attributable to Continental gaining working interest in the wells due to participants' not non-consenting.

This provided Continental the opportunity to increase our position in attractive properties. Similar to 2015, capital expenditures are expected to decrease throughout the year, with the spend in the fourth quarter of approximately $200 billion.

Based on current strip pricing and our current capital plans, we expect to be cash flow positive for the year. Production expense, G&A, and non-cash equity compensation continued to trend lower this quarter with our focus on cost and efficiency and on a Boe basis were benefited by the robust production in the first quarter.

Production expenses dropped to $3.76 per Boe in the first quarter, down from $3.86 per Boe in the fourth quarter 2015. Additionally first quarter G&A per Boe excluding equity compensation decreased by $0.57 to $1.11 per Boe versus $1.68 per Boe in fourth quarter 2015.

Non-cash equity compensation dropped to $0.44 per Boe in production, down $0.12 from $0.56 in the fourth quarter of 2015. All three of these metrics perform better than our guidance.

As noted, we will continue to monitor them and plan to provide updated guidance later this year as necessary. Total cash cost, including interest, was lower at $10.20 per Boe in the first quarter, down an impressive 17% from full year 2015.

Combined these low operating costs in first quarter 2016 provide a strong competitive advantage for Continental, not only in today's price environment, but also in a recovering market as margins will scale back up with commodity prices. Continental has one of the lowest cash costs in the industry which when coupled with our exceptional well results places us as a leader in capital efficiency.

First quarter oil differential was $7.78 per barrel below the midpoint of the guidance range of $7 to $9. The first quarter gas differential was negative $0.73 per Mcf, increasing from fourth quarter due to continued weakness in the NGL's market.

Though the first quarter gas differential was lighter than our current guidance, we expect to be within our guidance range for the full year as we are seeing improvement in NGL prices. Now, I'd like to turn to this year's and 2017's outlook.

For 2016, our capital budget remains at $920 million and is focused on spending within cash flow. The budget is cash flow neutral at an average WTI cost of $37 for the year.

As previously noted, last quarter, a move in WTI price by $5 will impact our full year cash flow by $150 million to $200 billion. So, obviously, we're forecasting significant positive cash flow at today's script in spite of low prices in January and February.

We look at potential changes to our cash allocations and $5 increments in WTI. As WTI increases to $45 essentially where we are today, we would apply the additional cash flow to reduce debt.

With the next $5 move, we would expect to balance adding completion crews to begin working down our Bakken DUC backlog, while also reducing debt. For reference, a completion crew can work down three wells to four wells per month.

Once we see WTI process around $60 with stability in the price, we would consider adding additional drilling rigs. Please note, we not only want a price recovery but also sustainability in prices before we would add any capital.

We will patiently monitor the macro environment and approach any adjustments to our plans in a disciplined manner. Looking beyond 2016 to 2017, we are well positioned for numerous scenarios.

2017 provides opportunities to CLR. Rig contracts continue to roll off and we have a great deal of optionality in terms of how we begin working down our DUC inventory.

As previously disclosed, we anticipate exiting 2016 with approximately 245 DUCs with 195 in the Bakken and 50 in Oklahoma. These DUCs provide a highly capital-efficient catalyst when we elect to begin completing them.

For instance, the 195 Bakken DUCs have an average EUR of 850 MBoe per well and could be completed at the current cost of approximately $3.5 million per well. Obviously, commodity prices will be the primary factor in the pace and timing of completing our DUCs.

This flexibility provides a wide range of possibilities in terms of 2017 maintenance capital and production. As examples, if we chose to target 2017 production flat at the low-end of our revised projected 2016 exit rate of 190,000 per Boe per day, this would imply 2017 CapEx of $900 million to $1 billion, while maintaining a flat DUC inventory throughout 2017.

These estimates reflect the higher exit rate we announced today. As another option, if we were to target holding flat at the midpoint of our annual guidance of 210,000 Boe per day, this would entail estimated CapEx of $1.1 billion to $1.3 billion.

These two scenarios are based on current cost and both target cash flow neutrality. Ultimate plans for 2017 will evolve and depend on a number of variables including commodity prices, market stability and our plans for years after 2017.

We continue to have ample liquidity and no near-term debt maturities. At the end of March, we had $940 million of borrowings against the credit facility.

Primarily due to the March timing of bond interest payments, our revolver balance increased by $87 million in the first quarter compared to yearend 2015. There will be a bit of lumpiness in the revolver due to the timing of interest payments, but on the full year basis, it will average out.

At current strip prices and under our current capital plan, we expect to be cash flow positive by a few hundred million dollars by the end of 2016 in spite of January and February's low commodity prices. As of April 29, we had $870 million of borrowings against the revolver, providing approximately $1.9 billion in available borrowing capacity under the facility.

Reduction in the revolver balance from March 31 is reflected at the proceeds being flat from the sale of our Wyoming leasehold. As Harold mentioned, we have additional non-core, non-producing assets that we could look to do similar liquidity enhancing transactions.

Remember this revolver is unsecured and there are no terms in the facility that would mandate collateral or a borrowing base calculation coming back into place. The revolver's sole financial covenant is a net debt to total capitalization ratio of no greater than 0.65.

And as of March 31, 2016, the company's net debt to total capitalization was 0.59. Under the terms of the credit agreement, this calculation of total capitalization specifically excludes any non-cash impairment charges after mid-2014.

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

Hi, everyone. Really great results.

I was hoping that you could speak a little bit more about better performance you see in the Bakken. From what I've seen looking at the state data, the recent wells seem to exhibit a relatively flat production period for several months.

So would first like to know if that's what you're seeing? And if so, what would you attribute that to?

Well, Drew. It's a good quick question.

It all boils down to essentially the enhanced completions that we're doing in the Bakken. These wells are outperforming our expectations, as a result.

We completed wells in 2015 with our enhanced completions. And we're early in these wells, because obviously they're coming on here first of the year.

I think we put 10 wells or 11 wells that were completed in 2015 on early part of this year as well as obviously the ones completed late last year. And with early time performance, it's really hard to project what they're doing and what we're seeing is these wells have a much flatter decline that we expected and producing at higher rate.

So it's a great situation to have. Essentially, we're seeing better performance from a Bakken enhanced completed wells than anticipated.

Thanks for that, Jack. And as you think about the rest of the portfolio, you have now I guess four density pilots and SCOOP completed and Meramec just went underway and from the industry peers as well.

You've provided some dimensioning around the Bakken inventory and you've reiterated it again today. Could you provide some kind of dimensioning around the depth of inventory in SCOOP and Meramec given the latest results?

Well, gosh, we've got well over a decade of just really high-quality inventory between our SCOOP and STACK. I don't have a number to give you today on the inventory, but it's what we're doing right now in STACK.

In fact, we're getting in there now at the part of the density – purpose of the density is to get an idea just how many wells we can drill essentially per drilling spacing unit in there. So rest assured, we have a very deep inventory of high-quality locations to drill in both of these plays.

And couple decades of inventory, quite frankly.

Thanks, Jack. That's it for me.

Yes, thanks. Ditto, great job.

Question on the condensate window. On the eve of some step-out activity down to the south and southwest, could you just review your thoughts on the condensate play and if there is a pretty black and white line between where you would develop, or can you envision a condensate development program if these wells show condensate beyond the Boden?

Okay. Yes, I was going to say, you're talking about the STACK area.

Okay. At this point, we really don't have any material change from what we've said previously.

We're still building our information base out here from wells we're drilling. As we said previously, we think at least 30% of our acreage is in the oil window and a great majority of the remaining acreage we think will be in the condensate window.

And the Boden being the first level that we put into that – that we drilled in the condensate window. So I guess I'd have to stay, you'd have to stay tuned here for a while to let us get some more information from these new wells that we are in the process of completing right now.

But early indications are that, as I said, 30% is in the oil window, and we kind of – from what we're seeing and based on our geologic model, we expect that to grow.

Okay. And then on the managed choke, is managed choke a best practice from an engineering perspective, or is there a price call in it?

I suspect that you don't necessarily need to do it if it's not a condensate well, but any thoughts there?

Yes, well, as you can see, the Foree is a pretty good example, the amount of production that we're pulling out of that well at nearly 5,000 pounds. You get into a situation with high pressured wells here that you've got both safety concern, production-related concerns, and there is no need of going (40:55) down in this price environment.

So all those things combined, I think, from an engineering practice, yes. From a production practice, yes.

Certainly from an economical practice, yes.

And the 10,000 BOE per day of curtailments in the quarter, in the second quarter, you reference that as being primarily STACK. What's the trigger to get those volumes on in the second half?

Yes. This is Gary Gould.

It is not primarily STACK. It's primarily SCOOP.

It's about 70% SCOOP, and it's about 30% STACK. Also when we're talking about our 10,000 BOE per day, it's about 80% gas and about 20% oil.

And so as far as getting it back on with it being gas, we'll be watching the prices more in the fall.

Okay. Terrific.

Thanks again.

Thank you. Good morning.

Morning.

Good morning.

You talked a bit towards the end of your comments regarding capital allocation at various oil price levels. Can you talk a bit more about where you would put rigs back to work first when the time is right, Bakken versus STACK versus SCOOP.

And if the productivity gains you've highlighted today could push down the price, you'd bring back additional rigs below the $60?

Well, Brian, it's going to be some time before we think about bringing on more rigs. I'd say as we stated and walked through the increments of $5 to $5, you saw that our primary emphasis, first of all, would be balance sheet, paying down debt, next would be DUCs and then maybe ramping up the completion of those DUCs before we ever considering bringing on rigs back.

So we're probably at the $60 range, and that can happen prior to year-end. But certainly the Bakken before with – anywhere else.

We're not planning anything toward bringing rigs back. And certainly we understand the nature of this business and the price spikes.

We're not chasing those. We're going to see stability before we even think about bringing rigs back in.

Great. Thank you.

And then also in a period where you and potentially others could be ramping up whether it be completions or one-day rigs, can you just talk about whether you're thinking the Bakken that there are any constraints in service availability and also in SCOOP as well?

This is Gary Gould. I can speak to that.

As far as availability, we continue to bid out on work in both areas very actively. And so as we continue to talk to service companies in both areas, they continue to have availability for us.

And so as we were to grow out of this, it's going to take a long time before prices increase significantly because there's a lot of spare crews out there, especially on the stim side.

We do, I thank to answer that. Additionally as far as our concerns, though, we do have concerns about availability at Bakken.

We hope a lot of these frac crews haven't gone away. It remains to be seen yet I think.

Great. And if I can ask one last quick one.

You mentioned in your comments non-operated partners were going on consent a little bit more often, freeing up some working interest for Continental. Are you seeing any signs of that changing at all?

I don't see any signs of it changing right now. We have some people here that obviously have financial issues, and we run into situations where people just can't go or don't.

Thank you.

Hey, good morning. Congratulations on another good operational quarter, guys.

Thanks, Brian.

Thanks, Brian.

Thanks, Brian.

Really on slide 12, with the STACK density test, where have you all been landing the laterals for the previous STACK wells? Has it been in the middle or the upper or have you all tested both of those already?

That's a good question, Brian. Our Ludwig and also our Quintle well, they were landed in the middle and the, let me see, it's going to be the Foree and our...

Bernhardt

...Bernhardt landed in the lower. So basically we tested the middle and the lower at this point with those four wells.

So the point being there, the reason I'm glad you brought that up is that we're actually seeing very good results from both of those zones.

Okay. And could we assume maybe one of the other or future STACK density test is going to test all three: the upper, middle, and lower?

Yes. As we said before, we break this into three reservoirs in here.

And we don't see all three developed in all units. On average, we're going to see two reservoirs developed per spacing unit, but there are some areas in here where we're going to see all three stacked on top of each other.

Okay.

And when we say three, obviously specific to the Meramec, it doesn't include the Woodford and the Osage reservoirs as well.

Okay. And maybe just one other one.

You talked about some other non-core asset sales. Is there a dollar amount you look to raise or you're just trying to trim the fat a little bit?

Well, it's easy when people have an interest in buying what you have. And that was the situation with Wyoming.

We see other interest in other non-core assets that the company owns. And obviously, we're not out here trying to sell at fire sale prices.

We would like to have value for it. And as people see opportunities within these non-core assets and show interest, we're going to try to deal with them.

All right, guys. Thanks.

Congratulations again.

Thank you, Brian.

Thank you.

Yes. My first one, Jack, you and several of your peers are doing the staggered lateral testing perhaps a bit earlier than we've seen in other plays as plays have matured.

Can you just comment on why? And just maybe some thoughts on your current pilot in the STACK.

Yes. Well, really it's an easy answer.

And that is just from experience with these places, we know where we need to go to understand what the full potential of each of these plays are. And we have just a lot of history behind this, us and others in the industry.

And so we know the real value here is getting a very clear picture of what the proper density is very early in the play. That way you maximize your development of the field.

So that's really the driver behind this. And so to me that's just really the bottom line.

Fair enough. You do have some STACK acreage in your Northwest Cana JV.

What is from an Continental perspective your strategy to delineate that acreage to the STACK?

Well, the Northwest Cana JDA is actually just a subset of STACK, and there is an area in there that we have essentially a JDA with SK, E&S and we are jointly going in and developing the Woodford there. But we retain the Meramec rights and actually are in the process of testing the Meramec in that area.

So it's a great opportunity because we have rigs in there that are (49:57) our acreage. (49:58) Meramec rights.

But as I said we're now moving into testing Meramec in those zones.

Okay. And my final question, just one of your peers who has liked what they've seen at the Meramec thus far did comment on seeing some variability in some of their initial results.

On the other hand, Jack, you guys have talked about much more consistency and repeatabilities. Wondering if you could maybe talk a little bit about that.

Does that reflect the fact that you have a lot of vertical penetrations here, so you have a good picture of the Meramec?

Yes. I'm going to let Glen Brown take that one.

Yes, I'd be glad to answer that. As you say, we have a lot of well control, logs from our developments in the area, up to 600 well control points out here.

We know where these reservoirs are, and across our acreage which is in the thicker parts and the over-pressured part of the STACK play, we're not seeing the variability that's been talked about. So we're really excited about developing higher levels, or upper, middle and lower levels out here.

And if we see some variability, we'll let you know, but we haven't seen it yet.

Okay.

I think it really depends on where your acreage is positioned and how the reservoirs are developed under your acreage, and right now, we see great continuity and great results, and so we're really pleased with what we're getting.

Great. Thanks a lot, gents.

Thanks, Arun

Good afternoon, guys.

Good morning, John.

I believe the original CapEx budget was $920 million, you're baking in about 5% cost reductions, but I think you had a little bit of flexibility where you thought internally you all could do better than that. I'm just curious through the first half of the year where you think cost reductions have shook out, because it sure seems like you're shaving a lot of cost in a lot of these major plays.

This is Gary Gould. And we are saving a lot of costs.

Really a lot of the ones that we're reflecting on this quarter are really operational efficiency costs. And so those are fantastic because they'll stick with us for the long-term.

And so as our engineers continue to look at the designs, whether it be on the drilling side or optimizing our completions, we expect to continue to work toward additional reductions. We expect to be able to see another 5% or so North in the Bakken and we expect to see as much as 10% or 20% this year down South where we're early in our plays and so we have more to learn, we're going to see more significant improvements in early stages of these plays.

Great. And then my one other question.

And looking at the density pilot in the STACK, you said there will be two others that you're going to do in the other parts of the play. Are you going to wait until the Ludwig density pilot is completed, or those will be done in short order here around the same time as the Ludwig?

No, we're going to proceed ahead. We're not going to be waiting for results from the Ludwig.

And in fact, we've basically approved doing the density pilot. We've selected and approved it here internally to do the pilot in the condensate window, and we're going to be reviewing the options that we're considering in the oil here in the next week or two.

Great. Thanks.

I appreciate it. Well done.

Thank you.

Thanks, John.

Thanks. Good morning, everybody.

Good morning.

Good morning, Doug.

I guess it's still morning. So, guys, I'm trying to understand where you are in terms of the enhanced completions in the STACK wells.

Obviously that has been driving uplifts to your type curves in the SCOOP. But how does the current completion compares what you're doing in the STACK?

In other words, is there another level of efficiency gains that once you get into manufacturing mode?

This is Gary Gould again. And the STACK, we're applying the learnings now that what we've already learned from our other plays.

And so right away, early on in STACK we started completing these wells, we had a lot of slick water hybrid which is mostly slick water, and then we also started applying a lot of sand to it. So, for instance, in the STACK we're already applying around 2,500 pounds per foot of sand based on the increases that we see in our other plays.

So we've already added STACK and that's where our type curve is based on these original completions that are already enhanced.

And that's your optimal stage spacing as well?

We still have a lot of experimentation to do on that. So there's a lot of parameters.

If you think about where Continental has been, the biggest changes we've made have been in our fluid types and the amount of proppant. But we continue to experiment on average stage length.

We continue to experiment on the percent of mesh size for our sand as well as other completion parameters. So there's always room for improvement and optimization.

These are continual item that our engineers work on.

Thanks...

You know, Doug...

Go ahead, Jack.

I was just going to say, I view this – what's happening with enhanced completions right now is actually kind of the next phase of exploration in these plays because as you can see, we continue to turn on more and more barrels and get better performance through this added technology. So it's just another phase of – to me it's just exploration.

We're testing a lot of different parameters. And in the end, for the most part they're all just delivering much better results.

So stay tuned. Each of these areas are going to have its own formula but they all play off of each other.

Jack, just that point on the related question, so the costs have -obviously you are doing sporadic wells right now. You are not – at least as far as I can tell – anywhere close to manufacturing mode yet.

So when you get to pad drilling, assuming you went that route, what do you think happens to the well cost relative to where you are on that?

It continues to go down. So in my experience as we move towards pad drilling, we see efficiencies both on the drilling side and the completion side that provide another range of 10% to 20% savings.

So the 75% doesn't assume that?

So what was your question?

The 75% IRR does not assume additional cost...

No, that's the current cost.

That's the current cost. And I guess what I'd point to is look at the drilling improvements that have been made in our density test.

We showed that slide and you can see the efficiencies that we gain from pad drilling. And that will be exciting to see as we continue to move into the development throughout all these plays.

Yes, the 75% is $45 oil in current cost. So we have upside in terms of commodity price obviously but also in terms of cost and efficiency.

And the Bakken is a good template for that what you saw in terms of improvement there moving to pad drilling. And we should get further into the play.

Well, last one, John, if I may, maybe this is for you. Can you just talk to the decision to defer production?

I don't know if there was any infrastructure issues there or just the parameters as to why you decided to do that? And I'll leave it there.

Thanks.

No, it's basically an economic decision in here for the most part. We see prices higher in the future and don't see the need to flow with it at these maximum rates.

Okay. Thanks, guys.

Good quarter.

Thank you.

Thanks, Doug.

Hello, all, and congrats on a great quarter and ops update.

Thank you.

Thank you.

Thank you.

So going back to page 12, what specifically led you guys to 1,320 feet spacing on the old window? and do you anticipate testing tighter in your follow-up pilot?

I'd say it's just kind of an experience factor in here when you get down to it. We still have a lot to learn about the reservoirs in here.

It very well could be that we could move to tighter spacing, but I guess we're erring on the side of maybe just being a little cautious here to not get them too close. I know others are talking about drilling tighter spacing out here and it very well may play out that way.

And so if you go back into the early days in the Bakken trying to figure out what was pilot density up there, we started pretty big and got down a lot tighter. So it's an evolution.

Got it. Makes sense.

And then moving over to the SCOOP well, what's the approximate timing on the May unit pilot and have you guys set the completion design for those wells?

That's a good question. And we've got that on the table and are discussing it.

But we haven't pulled the trigger to go ahead and start the completion there, yet.

And I imagine you guys will be looking at much more of a 2016 design versus the 2014 design? And with that said, if you guys do pull the trigger on it, there's really no reason we should expect any different result from the standpoint of a production uplift to what you've already experienced in the SCOOP condensate window?

No , I agree with you that in the end we are going to apply the enhanced completions here and that's actually one of the advantages of this slower period is pulling back on our pace of activity is that we've given us more time to actually monitor results. It allows us to be more strategic in completions that we're applying.

And so basically, monitor what we've done previously and really retool our thoughts. And so they May is going to be a better producer as a result of our delay in going after it because we've learned a whole bunch since when we first drilled those wells and remember we did some micro seismic in here and that taught us a whole bunch on basically the makeup of the completion that we think will be most effective.

Got it. And then one more if I could.

So, if we look at page 10 with your future Meramec oil step-outs, which one of those wells is most important to you guys from a derisking perspective? I mean, they're all going West so that's generally positive, but is there one that has greater risk in your view?

This is Glen Brown. I think they're all of equal importance.

As we move to the South and the West our reservoirs become significantly thicker. The reservoir qualities are even better than you see it in the shallow parts of this play.

We don't differentiate between these. All of these are very important to us.

Okay. Thanks for taking my call.

Thank you.

Thank you.

Thanks for taking my call, guys. So a question, maybe Harold, for the M&A side.

Again I'm just wondering maybe on acreage swaps, I guess, what I'm referring to would be specifically the Chesapeake sale this morning. I mean, it seemed to be that it might fit pretty well with some of what you have.

Again, most of your acreage obviously is quite good as well. So I'm just wondering how you view potential acreage swaps?

Well, we think we have premier acreage in the play, obviously. This substantiates a whole lot of what the real value is out here across this entire play.

So we feel validated in the play and also values out here in the play from this transaction. So it's I think market and certainly players within it continue to see how valuable these acres are.

Got it. Good.

Thank you. And then one last one, if I could.

Just remind me on the rig rollouts you do have this year and with those – how do you think about – does that play in your thought about either increase or decrease in activity or is it more just solely on your thoughts about upcoming pricing?

I think, it's primarily based on prices. We're utilizing all the rigs that we have, and we feel good about what we're doing.

And we'll just assess the – how that works out as far as pricing goes clearly the balance of the year.

And this is Pat Bent. A point of clarification on the rig roll-offs.

We don't have any rigs rolling off in 2016. That starts in earnest in 2017 where we'll see greater than 50% of the rigs coming off long-term contract, should we choose to go that direction.

Thanks for the clarification Pat. Thanks, Harold.

Thank you.

Hey, guys. I wanted to just ask you about the 15,000 acres you picked up in the STACK this quarter.

It looks a little bit northwest of the bulk of activity to-date. Just curious what you like about this acreage, and if you had to allocate that 15,000 to various windows, how would you do that?

Thanks.

Well, the acreage that we picked up is really kind of scattered throughout the play. But, obviously, we've picked it up on what we believe are very strategic measures that we've identified.

And so really it just complements our play and doesn't really substantially change anything at this point. As far as how much acreage is in the oil versus condensate window or any of that, right now, and these are just what we consider to be some key core acres that we're picking up.

Okay. Great.

This is Glen Brown. I'd add to that that we do combinations of deals.

But sometimes people get out of our wells, as Harold mentioned before. In our Boden unit, which is an exceptional unit for us, we had 50% of the participants get out.

And we have their interest for all the future development of that unit, no matter how many wells are in there.

Got it. Great.

And wanted to get your opinion on some of the secondary targets in the STACK. Meramec seems to be getting most of the love to-date.

But your thoughts on the Oswego and the Osage and plans to target those formations going forward? Thanks.

This is Glen Brown. We – the STACK is appropriately named because there are many, many formations above us that are in – are also in the pressure style, there's about a 3,000 foot column that's also over most – all of our acreage that has additional pressure, common names like the Morrow, Springer, Manning, Chester.

In addition, the Oswego and some of these other formations that are in the under pressure or normal pressured area are also targets that can be exploited as we go on in – over the years in these plays. I don't see the Oswego as being a wide-spread play since you mention that.

It's more of kind of a shoal and isolated units, and they're making some exceptional wells in them. But it's not really a resource play it's more of a local play.

But I'd add to that, you make a really good point though that there are a lot of undepreciated assets sitting above the work we're doing down in the Meramec and the Woodford. And the beauty of it is, is that, as we drill every Meramec and Woodford well we drill we get a free look basically at any pay zones above us.

So we're logging all that, and mapping all those reservoirs out, and we will be able to come back in at (1:06:05) and start harvesting some of these more – even conventional type reservoirs with horizontal drilling that will just be – to me, be lights out when we go drill those wells. And so it's one of those things that is just build there – as much asset as we're building in the Meramec, Osage and Woodford, we're building a lot of uphold value as well.

Thank you. Great update.

Thank you.

Good morning. Thanks for taking my questions and great quarter.

My first question pertains to the longer-term outlook for the Bakken for Continental Resources. Given the far better well economics available to Continental, on the SCOOP, the STACK and the Springer, how can the Bakken compete for capital over time?

I know that the asset is a legacy asset and Harold is really the father of the Bakken. But it feels like if you viewed it narrowly through the lens of just pure well economics the Bakken cannot compete.

I'd love to get your thoughts on that.

Well, if you'll go ahead and track it on up as prices improve and come back, what you find is that that becomes more valuable in the future, much more valuable in the future when you project those prices up. So this play, said and done by far, and that's just the way it looks out in the future to us.

Do you want to add to that?

Well, I was just going to say, and there's so many other things that you need to consider in that equation as well. It's not only the performance of the wells, but it's – if you look at the infrastructure that's being put in place and is in place now that totally changes the operating expenses.

And on top of that you've got the added pipeline capacity that's coming in. And so differentials are being driven down.

And so there's just – there's economies of scale in operations that just essentially make it more valuable. And on page five in our deck, if you go out there and take a look at it, Evercore ISI has put – they've got a chart that they've put together showing the – let me turn to that just here real quick.

It is on page five. They've put out a nice chart there.

This just basically is showing the breakeven that generated 10% rate of return, and here in the Bakken, 800 Mboe equivalent model, and it's in really – in their ranking it's in the top. It's the second out of what, I think there's about 30 on this chart as far as breakeven economics.

And so in the end, we don't see it the same way, we see it as being a great opportunity with lots of value to this company going forward.

Yeah, I don't mean to denigrate the Bakken. That's not it.

Actually anything it's more of a reflection of the incredible improvement in your well economics in the Anadarko basin. So that's really where the question came from.

And then my follow-up relates to some that's in the news right now, and Harold I think you've got your finger on the pulse pretty good of Oklahoma politics. But all these people upset about earthquakes in Oklahoma, do you see that as an issue we should consider, worry about?

Or is it not really an issue for your assets there in Oklahoma?

Well, you should not worry about it as far as from Continental's aspects, we don't have a well in it. So that's where we're at.

Obviously, this is tied to deep water over the Mississippi formation, and that's being controlled by the state. The state's handling it very well.

We see the number of these quite fallen off drastically. So they've got handled, and the Oklahoma Geological Survey and Secretary of Energy with the group that's over that, and they're doing a good job.

So I think those worries will abate. Obviously, that's being controlled well.

Thanks.

Well, thank you.

Yes.

Yes. Just a question on the STACK, it seems other companies are talking about seeing better results per lateral foot on the shorter laterals.

Y'all seem to be having very similar result per lateral foot on the longer versus the shorter. Why do you think you are seeing similar EURs per lateral foot while others are seeing better results with shorter laterals?

We go through this every play. It happens about the same way.

We have operators that tend not to be either be able to put longer lateral units together, cross units. It takes some expertise to do all that.

And so they obviously get into trying to build up the productivity of those. But it just comes down to footage penetrated and formation treated.

It comes out about 1.2 times on that next section as to what it will add in incremental value. It's just more economic if you can put those two units together, and we've been very successful in being able do it.

Our teams understand this very well, and we've got it down to where it's pretty fine art around here.

Okay. Thank you.

And as a follow-up, that was a really good well in Carter County with – in the SCOOP. Do you all plan to do some more drilling down there and – basically geologic mapping.

How big do you think that (1:12:17)?

Yes. The way it's mapped.

That's a little sub-basin that we call the Loco prospect, and it's nearly all HBP. We've been drilling in there for quite some time.

But what's was really great about that area is we're bringing the – we kind of stepped backed from it to reprocess some seismic, and during that time we're bringing the drilling efficiencies and completion efficiencies that we were working on in the SCOOP down back into the basin, and we're uplifting our performance there. Not that the performance there was bad to begin with.

We have a well that I'll just mention from last year, the Gentry well, Gentry 1-11-2XH; that was drilled last summer, put online, it was online for seven months, and that well has made 2 Bcf and 56,000 barrels and is currently making 198 barrels a day, 8.7 million cubic feet of gas at 1409 PSI on a 38 choke. That's not a slouch.

So, we have a number of wells in there. I don't really have time to go over all of them for you.

But we really like this basin. We have five more units to drill in there and will be totally HBP.

And we expect to be in pad there sometime in the near future. We have several other basins like that, and we'll share those with you, perhaps next time.

Thank you, and good results.

Thank you.

Thank you.

Good morning.

Good morning, Noel.

Just a couple things. Going back to the efficiencies in the STACK.

You reported a big cycle time improvement, I think 32% compared to last year on the spud-to-TD, I was just interested in hearing more about that, I was wondering if it was just the crews getting more experienced?

Yes. This is Pat Bent.

I think it's a number of factors. There is a component of consolidation within the industry, and so you have the better folks still working.

But in addition to that, you've spend a lot of time focusing on our target and so we're defining better potential, same time maintaining the reservoir quality that we drilled. But that allows us to do to the set extended targets versus immediate structure dip and so we're aiming at something 1,000 foot out and sliding less.

And so with the technological advancements that we have from a reliability and durability perspective on bits, on motors, on MWDs we've seen a significant improvement in vertical and lateral penetration rates and cycle timing improvement. So, I think there is more to come.

Great. And as far as the – your leasing in the STACK, you guys were early and with our company even standing alone in your optimism on Lane County.

The leasing rates and sort of the assumptions out there get either confirmed or changed. Had they been pretty volatile, the leasing prices, or are you seeing them sort of settle into on a more predictable range?

Well, we've certainly, I guess, our belief was good in Lane County, and – but most of – this is an area that is mostly leased up. I mean, it's not like there's a whole lot of lease that are out there.

So, prices are going up. But it's mostly leased up, and lot of it's HBP.

And so a lot of this acreage is – that we're making deals with different people.

I guess, I was wondering as you start identifying better where it trends gassier, where certain of that change over happens, I just wondered if that had an effect on what you were seeing?

Well, I mean, any time you move farther from activity the prices go down a little bit you know, but in the end there is – I'm not at this point the price per acre in STACK is going up. It just is.

So a lot of interest, it's one of the hottest places going on in the U.S. today and there's just a lot of activity.

And as Harold it's tough to put something together, so people have to pay a premium to get it.

Got it. Thanks a lot.

Thank you.

I would just like to thank everyone again for joining us on the call this morning. We look forward to reporting another outstanding quarter in August.

And with that, everyone have a great day.