Good morning, ladies and gentlemen, and welcome to the Continental Resources, Inc. Third Quarter 2020 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to turn the conference call over to Rory Sabino, Vice President of Investor Relations. Please go ahead.

Good morning, everyone, and thank you for joining us today. Welcome to today’s earnings call. We’ll start today’s call with remarks from Harold Hamm, Executive Chairman; Bill Berry, Chief Executive Officer; and Jack Stark, President and Chief Operating Officer; John Hart, Chief Financial Officer, and other members of management will be available during Q&A. Today’s call will contain forward-looking statements that address projections, assumptions and guidance. Actual results may differ materially from those contained in forward-looking statements. Please refer to the company’s SEC filings for additional information concerning these statements and risks. In addition, Continental does not undertake any obligation to update forward-looking statements made on this call. Finally, on the call, we will refer to certain non-GAAP financial measures. For a reconciliation of these measures to generally accepted accounting principles, please refer to the updated investor presentation that’s been posted on the company’s website at www.clr.com. With that, I will turn the call over to Mr. Hamm. Harold?

Yes. Thank you, Rory, and good morning, everyone. Under investment in the oil and gas industry has created a huge opportunity for today’s investors. Crude oil and natural gas inventories have been and continued to be drawn down worldwide. You have remained higher than normal levels at this time. Industry consolidation within our sector will continue to drive capital discipline as additional supplies are not needed at this time. I believe the winners in our sector will produce low cost operations and the most capital efficient barrels to deliver significant and consistent free cash flow. We deliver on both of those and that is why when you invest in commodities Continental Resources should be your number one choice. We’re undervalued and I believe we have the best value in our sector. We have industry-leading capital efficiency and lowest cost leadership amongst our peers. Our technological and operational expertise continues to drive these efficiencies. We have a large production base from our high quality assets with dominant position in both the Bakken and Oklahoma. Our assets afforded commodity optionality and gives us the capability of pivoting quickly and nimbly has demonstrated this quarter to take advantage of higher natural gas prices. And Jack and others will talk about that. We continue – we proactively manage our business with a long-term view on generating shareholder value, regardless of the price environment. This will be the fifth consecutive year of positive free cash flow for our company. We have unmatched shareholder alignment. We are always delivering innovative entrepreneurship across all of our teams and all of our operations. We’re responsibly fueling a better world through ESG stewardship and our company record best safety experience. We have a seasoned leadership team. Our sustainable free cash flow provides a direct path to further debt reduction and return of capital to shareholders. Despite recent volatility from demand concerns attributable to COVID, we remain optimistic and our ability to produce considerable sustainable shareholder value well into the future. Also I want to provide an update regarding American GulfCoast Select, the AGS Task Force continues to make great progress on technical recommendations and best practices around standardizing a new U.S. Gulf Coast financial and fiscal market for crude oil. In the third quarter, we saw an important announcement from Magellan Midstream Partners, which allows for crude oil from third-party pipelines to access Magellan East Houston terminal, allowing for additional access to Gulf Coast refineries and international waterborne markets. This is a natural evolution for the Houston crude oil market, providing a transparency, reliability, and liquidity required to be competitive in global oil markets. And there’s more to come. Finally, I wanted to provide my thoughts on the current state of the election. The election process is not final and we like you are waiting to see the results when all legal votes are counted. The energy jobs and energy security became the center of this election and motivated many voters and they swing States. I believe that had the Democrats position to eliminate oil and gas, they call fracking had that been known at the commencement of early voting. The outcome would have swung further to President Trump. Ironically with Joe Biden who helped craft the oil faded card administrations energy plan and a Fuel Use Act of 1977, which you also voted for. If you remember the Fuel Use Act mandated 100% coal usage for electricity generation, even as a EIS predicted disastrous environmental damage and it prohibited use of clean burning natural gas at the same time. And some of you remember, perhaps the acid rain that was caused. The reality is natural gas usage has dramatically improved as U.S. CO2 levels over the last three decades have declined to the point where we achieved the 2030 Paris Accord targets a decade early in 2020. Many energy supporting candidates did well in this election. And we will have several champions back in the Senate and the House. Congressional District Five in Oklahoma City was a prime example of energy voting and the importance of energy to local economies. I believe President Trump supportive energy jobs and his focus on economic prosperity bolstered his supporters. Americans care about the economy and the economic growth that will be powered by American energy. No matter the final outcome, Continental is well-positioned to be a leader and powering our nation’s recovery. While we wait to see the final results of the Presidential Election, the Senate will more than likely remain in the hands Republican leadership and the House Republican representation will be strengthened. This would serve as a backstop for any legislation that would be harmful for U.S. oil and gas producers. I will now turn the call over to Bill Berry.

Thank you, Harold, and good morning, everyone. As I shared with you my prepared remarks, I wanted to preface by say by highlighting five main takeaways. We’re seeing the best year ever for HSC and ESG performance. We had a very strong third quarter delivering $258 million of free cash flow. We are highly focused on free cash flow debt reduction and continued shareholder capital returns. Currently, debt reduction is our first priority. We continue to maintain our low cost leadership position. Our assets provide commodity optionality to position ourselves to benefit from relative movements and strip prices between oil and gas. So let me discuss these in a little more detail. Continental is on track to deliver outstanding HSC and ESG performance in 2020. We’re on pace to deliver our best year on safety performance ever in spite of significant industry and pandemic disruptions. This is attributable to the continued and exceptional efforts of our teams. I can’t thank them enough for all their work and their outstanding performance in these areas. Our gas capture has continued to be a focus having for us and currently is in excess of 99%, which is peer leading. We’re on track to deliver our fifth consecutive year of positive free cash flow, a leadership position versus our peers. Our culture is defined by our low cost operations. And the third quarter, as you can see on Slide 4, we again delivered low cost industry leadership. Our LOE per Boe was $3.19 for the quarter below our annual guidance, even as we were producing for part of the quarter at curtailed rates. This reflects the efficient nature of our assets and operations. Our cash G&A per Boe was also below annual initial guidance at $1.4. Based on these excellent results, we are lowering the upper range of guidance for LOE and cash G&A for the year to $3.50 to $3.75 and $1.10 to $1.30 respectively. We delivered lower capital expenditures in third quarter versus second quarter. As noted on Slide 6, third quarter CapEx was in line with our internal estimates and we are well-positioned to deliver full year annual CapEx trending at about $1.2 billion guidance level. We restored all previously deferred oil production that was curtailed during the second quarter. I came to did an exceptional job turning oil wells back on the line are 57% oil cut in the third quarter is above the guidance we provided you last quarter, suggesting it would be closer to 56% reflecting the return of our oil wells. Third quarter oil and total production figures both exceeded consensus estimates. We’re on track to deliver our full year 2020 production guidance of 155,000 to 165,000 barrels of oil per day, and 800 to 820 million cubic feet per day. We have also updated and tightened our December exit rate production to between 315,000 and 325,000 Boe per day. This sets us up nicely for improvements in both production and free cash flow in the second half of 2020, underscoring the strength of our assets and operations. For 2021, we are projecting a 65% to 75% of cash flows from operations reinvestment rate. Our sustainable shareholder value return continues with our ability to maximize free cash flow to pay down debt. This will be driven by capital efficiency, capital discipline, low cost leadership, and the commodity optionality afforded to us by our oil and gas assets. Based on this, we wanted to share with you some projections on free cash flow, CapEx and debt tarts, which you’ll find on Slide 7. Now you may have questions regarding the specific inputs of 2021, including rig counts, well panels, et cetera. As we were still in the process of finalizing our operational detail, we will provide that level of information and more at the usual time early next year. As part of this, we we’re projecting $1.2 billion to $1.3 billion CapEx in 2021. We’re projecting a low single digit production growth forecast year-over-year for 2021 with a cash flow breakeven of $32 WTI. We’ve talked about moderating growth for the past couple of years and we have consistently stated it is in prudent to overproduce into an oversupplied market and this is even more important today. The cornerstone of our 2021 plan is maximizing free cash flow to pay down debt. This has been a consistent message for us for several years and we have been – as we have been free cash flow positive since 2016. We expect to deliver significant organic free cash flow and projecting approximately $400 million at $40 WTI and $650 million at $45 WTI, with free cash flow yield ranging from 8% to 14%. We believe this will be top tier performance in the industry. Our main priority in 2021 will be debt paid down, we believe we will be reaching $5 billion or below of total debt by year end 2021. This would equate to approximately two times total debt to EBITDA at $45 oil. While our near-term goal is focus on approaching $4 billion or below by year end 2022 or 2023, depending on commodity prices, we are ultimately projecting total debt of $2 billion to $3 billion. We believe this is to be part of a strong program of capital returns to shareholders. I’ll remind investors that while our dividend has been suspended, but not terminated, both our shareholders and our board are very supportive of bringing the dividend back at the appropriate time after our debt is reduced. We also wanted to highlight that our assets provide optionality to capitalize on increasing gas prices in 2021. And we already have this benefit. We have a deep rich set of both oil and gas inventory across the Bakken and Oklahoma that allows us to be nimble and responsive to changes in commodity price fundamentals. Not only can we shift capital between the Bakken and Oklahoma, but within Oklahoma, we can shift between [indiscernible] projects. This provides an inherent advantage to Continental and we are already capturing this with hedges on the strengthened gas curve next year. We expect to capitalize on increasing gas prices in 2021, while deferring some of our strong oil projects for higher price opportunities until the back half of 2021. As shown on Slide 11, we saw this optionality in May and shifted our Oklahoma drilling rigs to gas. We currently have 202 million cubic feet per day hedge in 2021 with two-thirds representing collars with a weighted average floor of about $2.67 and a weighted average ceiling price of $3.44. Our Oklahoma gas wells can deliver over 50% rate of return at $3 Henry Hub, thanks to our low cost operations. We also have direct access to multiple premium markets from these Oklahoma assets. We have the inventory, the teams and the capabilities without transport bottlenecks to easily pursue either commodity as price fundamental warrant. Finally, I did want to highlight the latest update regarding a potential accelerator for debt paying down, which is a partial monetization of our water infrastructure assets. With strategic water infrastructure first in Bakken and Oklahoma, we believe our unique water opportunity is a differentiator. We have executed a non-binding term sheet with Six Street a $47 billion global investment firm with a lot of experience in energy and infrastructure partnerships. On this opportunity for a significant non-controlling interest and our water infrastructure assets. Proceeds of this pending transactions will be earmarked for accelerated debt reduction. We’re currently working with Six Street regarding definitive documents and our targeting confirmation of the transaction later this year or early 2021. This debt reduction of accelerate would be in addition to the organic debt reduction schedule outlined earlier in my comments and is not reflected in any of our slides. We have an extremely talented and dedicated team at Continental, and they are absolutely confident in our ability to maximize cash flow, deliver low cost operations and generate sustainable shareholder value. Our teams will continue operating from position of strength and we commend their ingenuity, discipline and expertise. The cornerstone of our 2021 plan is maximizing free cash flow driven by capital discipline, appear leading cost profile and commodity optionality afforded by our assets. The output of this program is impressive and is underscored by strong free cash flow generation. I’d now like to turn the call over to Jack.

Thanks, Bill, and good morning, everyone. I want to start out by thanking our employees for their hard work and dedication that is established Continental as a low cost leader among our oil weighted peers. Innovations from our employees continue to be implemented every day to lower costs and increase capital efficiencies across to all aspects of our business, while keeping safety job one. As Bill said, all wells are back on production. This includes 21 SCOOP and 42 Bakken wells that were turned to production during the third quarter. These third quarter wells are producing in line with expectations going to out that 77% of the production from the new wells in SCOOP was oil. We’ve completed 52 wells in Oklahoma this year through the third quarter, primarily targeting the oil and condensate windows at SCOOP, approximately 90% of these wells are Woodford producers in SpringBoard 1, as we moved from the Springer to the Woodford reservoir in phase 2 of our row development. All total, we have completed 78 Woodford producers in SpringBoard 1 and there is a chart on Slide 9 illustrates the average Woodford well performance is tracking right on top of the type curve we’ve published one year ago. This highlights how well our teams know their assets in Oklahoma and reinforces the fact that we deliver what we say. The second chart on Slide 9 shows that we are seeing improved performance on a unit basis compared to legacy units due to continued improvements in completion design. Combined with the 24% decrease in completed well costs achieved over the last two years, capital efficiencies from our Oklahoma operations have never been better. Currently, Springboard 1 is approximately 50% developed. We recently closed a very strategic acquisition in SCOOP that added approximately 19,500 net acres and up to 185 high quality wells to our inventory that are oil weighted and have demonstrated returns of 35% to 50% at current strip prices. This is a great example of the strategic bolt-on acquisitions we target in our core operating areas. Most of these properties are located in the SpringBoard 3 area where we are targeting multilayer reservoirs, including the Woodford, Sycamore and Springer reservoirs that are all prudent. Continental currently controls approximately 33,000 net acres in SpringBoard 3, covering an area approximately 76 square miles in size and approximately 80% of the acreage is HBP. We estimate that up to 260 operated wells could be drilled in the Sycamore and Woodford reservoirs alone at an average working interest of 70%. Production area is oil weighted and the performance of the wells competes head-to-head with our SpringBoard 1 and 2 areas. For perspective, the charts on Slide 10 show the impressive performance we’ve seen from four recently completed Woodford and Sycamore delineation wells in our SpringBoard 3 and 4 areas. These charts include two Woodford and two Sycamore producers and 60% to 70% of the production is oil. Names and locations have been withheld for competitive reasons, which you can see these are outstanding producers. Currently, large of these wells ranged from about 1.5 million to 2.5 million Boe per well. As we’ve seen in SpringBoard 1, our capital efficiencies will benefit greatly from the economy of scale as we develop these projects. [indiscernible] growing Oklahoma assets is that they provide great optionality to both oil and gas. As shown on Slide 11, approximately 70% of our rigs were focused on oil weighted assets in 2019. In the second quarter of 2020, we strategically shifted our rigs to more gas weighted assets in anticipation of the run-up in natural gas prices and supplies predictably wane. Gas prices have almost doubled since making that decision, and over the last few weeks, we have turned 20 new wells to production that combined a producing approximately 175 million cubic feet of gas per day and 10,700 barrels of oil per day on flowback. These rates are still climbing and we expect rates in excess of 250 million cubic feet of gas per day, as well as continue to clean up these prolific gas producing wells are benefiting from today’s strong gas prices and are expected to deliver 50% rate of return at $3 gas. Given the current market dynamics, we anticipate natural gas prices will continue to strengthen in 2021 and 2022 and we plan to keep our Oklahoma is focused on gas weighted wells for the near future. Operationally, Slide 8 shows that efficiencies have driven our complete well cost in Bakken and Oklahoma down 14% and 24% respectively since 2018. The majority of the cost savings have occurred this year and 70% to 80% of these cost reductions are structural in nature. Big news for the quarter is that our Bakken drilling costs dropped below $2 million for the first time. This is 20% below our average cost in 2019 and was driven by the structural changes in techniques and design that shaved another 3.4 days off of our drill times. Today, our routine spread to TD is 11 days and we believe we’re on the track to achieve is $6.9 million total completed well cost in the near future. This is an all-in costs, including four facilities and artificial lift. In Oklahoma, we’re targeting similar results with an all-in well cost of $8.9 million. Looking ahead, we plan to continue drilling with two rigs in the Bakken and three rigs in Oklahoma through year end. Bakken completions will resume with one stim crew in late November and two additional crews by early December. Company-wide, we expect that the 46 gross operated wells will be turned to production by year end, all of which have been stimulated and are being prepared to flow. Year-end, we expect to have approximately 140 decks and 145 wells in progress. With that, we’re ready to begin the Q&A section of our call, and I will turn the call back over to the operator.

We will now begin the question-and-answer session. [Operator Instructions] Our first question will come from Doug Leggate of Bank of America. Please go ahead.

Good morning. This is John Abbott on for Doug Leggate. Our first question is on the corporate break even. And if we went back to your commentary during the second quarter, it seemed to cash flow break even was in the upper 30 to low 40s. When we look at your slide number 7, where you suggest that you can generate $200 million of free cash flow at $35, it seems that you are break even has fallen. Let’s say maybe to $32. Could you explain sort of the change during between the second quarter and the third quarter, and it’s a lower sustainable break even – sustainable on a multi-year basis.

I mean, the breakevens of the factor of the capital you choose to invest. We have a very low maintenance costs relative to peers. We have exceptionally well-performing assets. We’re benefiting from a higher gas prices as well on that portion of the streams. So we are. So as we look to 2021, we’ll come out with full formal guidance on that in February. We’ve given you some indicators now. Yes, we do see the break even is roughly $32 next year. I don’t think that’s too dissimilar from where we were before we were indicating kind of in the mid-30s. But it depends on the capital program at any given time and where you’re putting those assets and the productivity. Additionally, as you’ve seen, we’ve had substantial improvement in well cost and we’re projecting obviously to continue seeing more as Jack alluded to earlier. So I think we’re extremely well positioned not only for next year, but for the balance of this year. We’ve got a proven track is $258 million of free cash flow in the third quarter is just an appetizer.

And then for our follow-up question, I know recognizing that you may be limiting what you can say, given that you just entered into non-binding agreement. Do you still believe in the $1 billion value for – over $1 billion value for the water business? And if you were to sell a portion of that, how much might you sell and how do you – how should we think about the impact maybe OpEx to your well costs from a partial sale?

Yes, we’re not obvious reasons, not able to get into the specificity of the agreement right now, we’re in the process of definitive documentation. And so that’ll be rolling out towards the end of the year, first of next year. What I can say is that when you looked at the valuations in the past, those valuations that we had described were predicated on $55 mid-cycle oil prices and associated drilling programs. So obviously, that’s been attenuated somewhat anticipation is that they’ll grow back at that point in time – at some point in time, we’ll be actually back at that kind of mid-cycle pricing and mid-cycle drilling activity. So, but right now, we’re not able to share with you any of the details of the contract for obvious reasons.

On the operating cost impact that you asked about, we’ve talked about that in previous quarters. So two points on that, you won’t notice it’s within our guidance ranges. And the second part of that is, it means that it’s very low, it’s low single digit pennies per Boe. So it’s not a dramatic impact. The proceeds you’ll notice, because they’re going to go directly today and then that’s going to be a significant and extremely beneficial impact.

Hey, thank you very much and thought it was a good quarter.

Thank you.

The next question comes from Derrick Whitfield of Stifel. Please go ahead.

Thanks and good morning all.

Hi, Derrick. Good morning.

Probably starting with just kind of the strategy pivot or slight strategy pivot into gas. Cash flow optimization is certainly a great business, if you can hedge it as you are. The biggest concern I’ve heard from investors is that oil could materially decline in your 2021 outlook. As I read and listened to your comments, it’s certainly projects the more balanced tone with the continued activity in the Bakken may potential return to oil weighted activity in Oklahoma in the second half. That to us implies a modestly – a flat to modestly down oil profile. Is that a fair read?

Yes, we’re really not given gas specific guidance at this point in time. For the main reason is that as you described the gas, the fundamentals are a lot stronger. All the fundamentals are not what we think they’ll ultimately be. We brought a significant old inventory that we will bring back on when fundamentals start strengthening. So if that strengthening happens in the beginning of the year, we’ll shift all. If it starts happening later in the year, we’ll begin. The gas is still strong. We shift into gas. And so focus you see in there is really cash flow focus. And I think you can see that described by what Jack was highlighting. We’re bringing on equivalent of about over 30,000 Boes of gas. We intentionally did that by moving rigs from oil to gas. So we could’ve kept drilling a hole, but from a cash flow optimization, from a capital efficiency, that makes no sense to do that. And so what we all see is that optionality is what we’re talking about is really, really important to this company and the differentiation of this company. Because with that optionality, we can go drill gas wells or we can drill oil wells depending on what the strip is showing us and using hedge to be able to make sure we’re assured of getting those prices great.

Great. And as my follow-up, I wanted to focus on basic fundamentals for Oklahoma. And in addition to a strengthening Henry Hub price, is it also reasonable to expect tighter dips in light of recent pipeline additions and the declining associated gas profile?

Yeah, I think, of course you saw the net back prices, improving from Q2 to Q3 from $0.12 to $0.98. And that was – as an expectation, we’ll continue to see that type of strengthening rather than Chang here Vice President of our Marketing and might have Aaron comment also on the dips in particular.

Yes, Derrick, I think for the reasons that you mentioned, we would expect a stronger differentials as we continue throughout the end of this year and into next, as production in Oklahoma continues to decline. We’re probably 80% to 85% statewide off of the peak in 2019. And we were a bit of factor of the new pipeline coming in service earlier this year as well. So that continued lengthen capacity relative to supply is going to continue to remain structural for differentials.

That’s great. Very helpful. Thanks guys.

The next question comes from Brad Heffern of RBC Capital Markets. Please go ahead.

Hey, good morning, everyone. Just as another follow on question on the water business, obviously, I don’t want to pin you down a too much. But can you verify that the sort of debt targets and walk that you give on Slide 7 do not include the potential water sale?

Yes. Thanks for bringing that up, Bradley. And I put it in the script, but also wanted to appreciate you’re asking a question, because I do want to highlight that. But none of those slides, none of those projections of debt have included any of the contribution of Water Co assets being focused on reducing the debt level. We will – as I stated, we marked those for reducing the debt. What you’re saying in that schedule that we’ve highlighted where we’re going down to $4 billion of total debt, and then going below that. That’s all from our organic activities, none of that is from any type of a dependency on the Water Co and this will be an accelerator. So the proceeds we received from Water Co we reduce that even further at a more rapid pace than whether on those slides.

Okay, thank you for that. And then on the Bakken, it’s been a little bit more than a year since you guys gave those very wide step-out results. I was wondering if you could just give an update on, whether you pursued more step out since then. And maybe just broader commentary on how you see the core inventory in the Bakken shaping up at this point.

Yes, you bet. We are and have completed some wells that are step outs further to the South following up to our previous successes. And so we’ll have some of those results to talk about here in the fourth quarter.

Thank you. Go ahead.

It’s safe to say though that basically while we’ve basically saw and I was step out as basically proven out across volume.

It’s a good point, Harold. We are, I guess, the main point of your question here is, are we still pleased with the results we’re seeing as in the step outs? And yes, we definitely are. And then we see that as just continuing to be a growing part of our portfolio.

Okay. Thank you.

The next question comes from Neal Dingmann of Truist Securities. Please go ahead.

Good morning all. This is Nate Svensson on for Neal. Thanks for taking my questions. So my first question with regards to your latest SCOOP acquisition. So it looks like the acquisition might be quite far South and the place on, if you could just discuss your thoughts on that part of the SCOOP versus a more central or northern areas of the plane.

Well, it’s – you’re correct in the sense it’s a little bit further south, but what you’re seeing down in this area is we’re seeing more, I guess, I would say more oil weighted, oil weighted performance from the wells down in this area. I think those two or four wells that we showed you there are a great example of the type of performance you’re seeing. And as you get down south, we’re seeing that we’re have multiple reservoirs plus multiple zones within those reservoirs that we are targeting. In the Sycamore, we have a couple of targets in there that we have and also in the Woodford it gets we also see the thickening in this area and have two targets in there. So we do have multiple reservoirs with multiple targets within them. And of course we also see the Springer being a component in this area as well. So it is a oil rich very, I guess I would say, it’s an area that we’re pleased with and we’re going to continue to build our position there.

That’s super helpful. And for the follow-up, I’m just hoping you can find your thoughts on the latest the Dakota access developments. So it seems like there were some incrementally negative press surrounding the oral arguments that took place in the DC court of appeals earlier this week. So I’m just wondering if you have thoughts around the eventual outcome of that have changed at all.

Unfortunately, I think you broke up just a little bit. Would you mind repeating it, Nate?

Yes, no problem. No problem. So I was just wondering if you could provide your additional thoughts on the latest Dakota access developments. It seems like there was negative press that came out surrounding the war arguments in the DC court of appeals earlier this week. So just wondering if your thoughts are changed at all on that.

On dapple hopefully you would have seen be transferred as comments yesterday. And they came out feeling very strong that there legal cases is still appropriate. They’ve got a strong case. Their position is a real wall prevail in that, they do not expect that that will be shut down.

Okay, great. Appreciate the commentary. Thanks guys.

The next question comes from Arun Jayaram of JPMorgan. Please go ahead.

Yes, good morning, gentlemen. I was wondering if you could shed a bit more light on what looks to be a pretty dynamic capital allocation programs, as we think about next year. And I know it’s early, you haven’t given us your official guide, but I’m just, I’m just trying to think about, as we look to model next year, how – today you’re thinking about kind of capital allocation between the North and the South. And where some of the capital that you’re using on some of the gas opportunities, where is that being allocated from?

So if you look at the capital program we’ve got going on right now, it’s – we’ve got three rigs in the South and two of the North. And so there’s a possibility we may continue with that. That’s about the same rig pace we’ll be utilizing in 2021. Again, we might move some things around depending on what the commodity prices are doing. But we’ve been real pleased with our movement in May of and then as you’re everyone will call and I’m sure the gas prices were and the dollar $60 range or so with that point in time. And then we ended up moving a lot of rigs into the gas area to start accessing the – what we thought was going to be a stronger fundamentals on gas. That’s proven out off-take for gases, as they’re in Jane mentioned earlier in the, in Oklahoma is real strong. We’ve got flexibility in the access to good markets. So I know that’s not a lot of specificity with what you’re really wanting to understand as far as modeling, whether we’re going to be drilling in the North of the South, but you can almost in your models, look at what your perspective is for the stronger commodity price. And that’s where we’re going to be drilling.

Got it, got it. And maybe one for John Hart, we understand that you are negotiating here and maybe not wanting to provide too many details with Six Street here, but what are some of the broader objectives? Clearly, debt reduction is something that you’re thinking about, what are some of the pushes and pulls as we think about you getting to the finish line and an agreement there?

It is a situation where we can’t disclose any more than we have. We’ll – we did give some indications of timing on that. So we’re looking to the future of having something in the not too distant future to announce on that more. I think there are a lot of factors. These are assets that are critical to our ongoing operations and growth within the basins we’re at their assets that we can grow substantially in the value of that. And so they are very important assets partnering with someone in a financial capacity, those proceeds will be earmarked towards immediate near term debt reduction and acceleration of that as compared to what we’ve got modeled in the strip. But we need to get across that finish line first. Once we achieve that, we’ll come out with more information for you at that time.

So we anticipate put all the slides together that showed cash flow, show debt reduction without taking any credit for any type of Water Co transaction. Because as you know, on any of these things, there’s always possibility they don’t work out. And we want to make sure that there’s a path to the debt targets that we have in front of us. And that’s why those slides are the important one. And as John just mentioned, this’ll be an accelerated, we’ll just move it more money into that and bring those debt targets ahead on our schedule.

Our cash flow generation and our debt reduction without doing anything on Water Co are extremely impressive numbers. This is the fifth consecutive year that we’ve generated free cash flow. We’ve given you indications about 2021. Obviously, the cash flow yield on that is dramatic at the top end of peer group. I mean, competes across the industries and with being able to do something with Water Co only accelerates and amplifies that we’re very well positioned, again, $258 million of free cash flow in the midst of an ongoing pandemic here in the third quarter. I think that’s very impressive. A lot of companies have hopes and aspirations we have reality, low cost and stronger generation capacity with a deep inventory.

And that next year free cash flow guide is what $400 million at $40. Is that right?

Yes. We gave you some ranges on that $400 million at $40, $650 million at $45, $200 million at $35, a breakeven of $32. We also did something we haven’t done before. We gave you a reinvestment range of a 65% to 75%. So I think we’ve given you a lot of variables there. What we hope you’re going from it is just what our capacity is and our ability. Our job is to generate regardless of commodity pricing. And we’ve got a proven history of being able to do that.

Great. Thanks a lot. Go ahead.

And Arun, it’s Rory. You can see some of the details in his fingers that John provided on Slide 7 of the deck as well.

Yes, I did catch that.

Slide 7, certainly want to focus on Slide 4, comparing to a broader group, Slide 5, the capital efficiency and cost leadership relative and then Slide 7. There’s a lot in there to get your hands around and it’s all third-party data. That’s a very viable. It’s true. It’s very strong.

Great, gentlemen. Thank you for that.

Thank you, Arun. Good to talk to you.

The next question comes from Brian Singer of Goldman Sachs. Please go ahead.

Thank you, good morning.

Good morning, Brian.

Good morning.

I wanted to ask on the production trajectory, because there’s I think a lot of moving pieces that that you’ve kind of talked to in your press release. It seems like there’s a big step up coming here on the fourth quarter with the strong volumes that you’re highlighting on the natural gas side in Oklahoma. And then you also talk about mid-single digit, low to – sorry, low-single digit production growth on a year-on-year average basis in 2021. That would appear to imply a declining trajectory on a Boe a day basis over the course of next year. But I wondered if you could just kind of comment on how you see that production trajectory for both oil and natural gas sequentially over the next few quarters.

We’ll come out with a lot more on 2021 in February. We did give you indications that we’re projecting a low-single digit growth next year, year-over-year. Exit to exit, we’ll come out with that in February. I’m not particularly worried about a decline or anything of that nature or significant one is I think you said you do see variability between quarter-to-quarter just depending on the timing of when different projects are coming on. And obviously we focus on very sizeable projects of scale, and you can bring on a lot of volume in any given period of time. So there’s normal fluctuation in there. I think we feel good about 2021, particularly the cash flow generation and the depth and quality of inventory that underlies that in an oil, gas, and condensate nature to where we can optimize cash flows depending on whatever the particular market is. So I think we’re set up well for 2021.

Yes. The other point on that $250 million that Jack talked about, that we’re bringing on, we’re wrapping into that. So it’s not an instantaneous $250 million to go into your calculus there.

Great. Thanks. And then my follow-up is on the inventory side. Can you just talk about developments in the Bakken, in particular since that sometimes is not necessarily as talked about that in terms of enhancing inventory either within the core or pushing out beyond the quarter-over-quarter.

Tanks, Brian. As we talked about before, we do have some tests going on that are basically confirmations outside, down south in the extension areas. And we are pleased with the initial results we’re seeing there. But from an inventory standpoint, maybe we just step back and take a look at it and just if you look at our inventory as a company and its capable of growing our production at a 5% to 6% compound annual growth rate for the next 10 years. And the inventory that we’ve got scheduled to achieve this growth over the first five years, represents about a third of our inventory quarterly and delivers a 30% to 50% rate of return at $40 and $50 WTI respectably. So and oil cut over these five years right now, it seems like you could say the average around 35%. So and this is something I think really should be pointed out is that this is a well-defined inventory with proven reservoirs with demonstrated well density. And it’s not assumed there’s – this is our assets or we know our assets well, as you saw, from just say the results in our springboard one area. I mean a year ago, we predicted an anticipated the performance of the Woodford wells and you can see how there’s great follow through there. So point there is that we really understand our assets and we’re not estimating that we have x density or x number of reservoirs that will produce, we know these reservoirs, and that is really key and probably a differentiator and a lot of ways of our inventory from others. And the fact that it is very well known, and that’s why our performance year-year-over and quarter-over-quarter from our assets is very, very repeatable, so and predictable in our production performance guidance, and also obviously our cash flow. So anyways, I just think that that maybe gives you a better broader perspective of our inventory and in an Oklahoma, I have to say, we added on this nice bolt-on acquisition. We told we’ve always said in these in times like these, we find that this is an opportune time for us to grow. And we like to do it through bolt-ons. And obviously, we’ve done that here this quarter. We also added a smaller bolt-on earlier this year, in over and above this acquisition, we mentioned here of 19,500, we’ve actually in Oklahoma put almost that much more acreage, basically doubled that adding – by adding almost another 20,000 acres in Oklahoma this year, doing it really pretty much under the radar, but getting it in core areas of our operations. And so I really think that this is just know that we’re continuing to build our inventory in our core areas. And we see that as just the opportunities that are always show themselves in times like these. So we’re really pleased with where our inventory is and where it’s going. And so I’ll leave it at that. Thanks.

Thank you.

The next question comes from Joseph McKay of Wells Fargo. Please go ahead.

Hey guys, this is Joe on for Nitin. I know we got some thoughts around the election in the opening remarks, but could you just give a little more detail around how you’re thinking about the outlook for the regulatory environment moving forward, given what we know right now?

Yes. That the way that dam sometimes like to play during the last President Obama’s administration, we’ve suffered death by a thousand cuts. We were able to survive it, but fight him off with the legislation and hold him off best we can. And thank goodness, it looks like Obama control the Senate add to the House representation. So that’s the game with a plan, again, to hold them at Bay. So we will have a work cut out if it goes on way. And we’re used to playing that game and that it’ll be up to us again to do that again. The good thing that is, I like to talk about earlier, I think everybody, very strong support turned out because of the back that the Democrats want to handle on gas, nobody want to do that. Hereby realizes that this is very, very important. Continental is lucky. We have very low federal exposure, less than 7% or something close to that. And so we’re not going to be fighting the game, fight the problem like other people might be. But anyway, that that’s what I said. Good question. Thank you.

Got it, thanks. And then you guys – you mentioned the more constructive outlook for the natural gas market. Can you just provide some quick thoughts around how you see NGL – yes, NGLs?

The question was, how do we see NGLs? Was that the question?

Yes.

Yes. This is Aaron Chang. I think similar to the crude oil appreciation that we’ve seen from the second quarter. We’ve seen that same appreciation our NGL pricing realizations as we move into the third quarter, we’d expect it to continue to increase through the end of the year and into 2021.

What about third NGLs with gas frame in Oklahoma? Is that correct?

It’s our acreage position in Oklahoma is about a third condensate, a third dry gas and a third earlier, that condensate is a very rich condensate to the NGL uplift on that can be very significant to our cash flows and obviously the returns and et cetera. So we’ve got a very valuable inventory position and we’ve got a lot of good commodity option outage. We talked about on the call.

Thank you.

Thank you.

The next question comes from Jeanine Wai of Barclays. Please go ahead.

Hi, good morning, everyone. This is Jeanine Wai. Thanks for taking my questions.

Hi, thank you.

So my question is really just on Slide 10 and we saw the disclosure on SpringBoard III and SpringBoard IV. And we’re wondering maybe if you could talk a little more broadly about any quality differences between SpringBoard I and then the subsequent SpringBoard in terms of oil cut and consistency. It looks like the well results that you provided on Slide 10 are very oily, but we know that it’s just a limited subset. Thank you.

Right. Well, I think what you can see there is a type curve we’ve got on Slide 10 comes directly from SpringBoard I. And you can see these was performing right in line actually outperforming that curve. And so as far as any differences in contrast between the two, I mean, we’re actually seeing this area right now, and these are delineation wells that type – the dash line there is that 1.5, that’s a unit curve. So you’d expect these wells mainly produce a bit more, but these are really outperforming that, that a unit type curve by a significant margin. And so we’re very pleased with the results and I think it has to do with reservoir quality in this area. And so like all of these areas are just, I mean very good performing areas. We have no concerns at all. And in fact, I’m very pleased with this and pleased to combine we’ve managed to put together about 40,000 additional acres in these areas pretty much under the radar during last year.

Great. Thank you very much.

Thank you.

The next question comes from Noel Parks of Coker & Palmer. Please go ahead.

Good morning.

Hello, good morning.

I was interested in hearing a little bit more about the bolt-on acquisition you did in the SCOOP Springer. And just curious about the acreage that you bought how long had the prior owner been in the play. And I just curious whether they had been actively drilling or had sort of – or had sort of neglected the acreage. And I also wondering if since you said its right in proximity to stuff you already hold. I was wondering if this was the acreage that was on your radar screen way back when you were sort of building the initial SCOOP position back in, I guess we’re talking 2012 timeframe. So this real familiar acreage to you in other words?

Well, I’ll speak to that. This is a prior spend in the industry for a good while and we’ve dealt with them extensively over time. And so they weren’t new to the play. And so anyway, we’ve had a good relationship with them.

And so it is – have they been actively working at or had they – had capital constraints and so forth.

No, they’re an active player.

They were – actually were still an active player. And I guess I’m curious then what the process of getting the valuation was like, whether it was one of the easier things to deal with upfront or did it take you awhile to sort of hit the bid ask on price.

This time by, we’ve dealt with a long time and so normal process. Thank you.

Okay. I guess just when trying to get out a little bit is, we’ve all been talking about the obvious case for consolidation for so long. So, and maybe you can just talk more generally about what you’re seeing in the SCOOP. I’m just trying to get at sort of why now and do you think seeing this deal might make a few other people think a little more seriously about selling?

Well, we’ve been active in the area for a while. So this is a combination of acreage from a player plus other players is as Jack was highlighting. So it’s not just one event that we’ve been picking up acreage in this area. This is something that’s been going on ever since we got in the SCOOP. So it really gets down to understanding your geology and understanding the geography and then making sure you’re in the right spot. Sometimes different people have different perspectives. And so this is something that we’ve been pursuing for quite some time is continuing to increase our ownership in the area that we know is geologically good. And so it’s not something that just happened over the last month since all the merger activity going on.

Yes, I agree, Bill. I mean this is just standard operating procedure for us. If we went back in time, you’d find that we do this each year. And these are just continued bolt-ons and strategic moves that we make just to continue to bolster our position in core areas that we like and have good geologic reasons and performance reasons why we did.

Yes, I’m going to build on Jack’s comment, just because he made a really good point. This is something that we do. It’s a strength of the company here. We built this company on an organic development. That’s who we are. We have good capabilities in that space. And so we’re always looking with our GSI’s team where we should be going next, whether it’s proximal to what we have, or maybe out in different areas. So that organic growth is just part of who we are part of our DNA.

It takes minimal integration to make it happen, right.

Right. It dovetails right into our existing operations they won.

This concludes our question-and-answer session. I would like to turn the conference back over to Rory Sabino for any closing remarks.

Thank you, again for everyone joining us today. Please reach out to the IR team for with any additional questions. I would like to turn the call over to Mr. Hamm for some closing remarks.

Yes. Thanks, Rory. My heart had is up to Bill and his team for their great execution and recurring 95%, 97% of our workforce to the workstation beginning in early May and allowing them to perform at this very highest level, taking advantage of existing opportunities during this awful worldwide pandemic. Thanks to all of Continental’s great workforce. I know that many of you sacrificed a lot. Have a good day and this ends our third quarter call.

The conference is now concluded. Thank you for attending today’s presentation. And you may now disconnect.