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spk11: 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. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. 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.
spk08: 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'll 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.
spk14: Harold? Thank you, Rory, and good morning, everyone. Underinvestment in the oil and gas industry has created a huge opportunity for today's investors. Crude oil and natural gas inventories have been and continue to be drawn down worldwide, yet remain higher than normal levels at this time. The 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 resource should be your number one choice. We are 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 as 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 policy 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 are 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 in our ability to produce considerable sustainable shareholder value well into the future. I also wanted to provide an update regarding American Gulf Coast 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. Energy jobs and energy security became the center of this election and motivated many voters in these 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, it was Joe Biden who helped craft the ill-fated Carter administration's energy plan and his fuel use act of 1977. which you also voted for. If you'll remember, the Fuel Use Act mandated 100% coal usage for electricity generation. Even as the 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 5 in Oklahoma City was a prime example of energy voting and the importance of energy to local economies. I believe President Trump's support of 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 in 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 of Republican leadership, and the House Republican representation will be strengthened. This should 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.
spk16: Thank you, Harold, and good morning, everyone. As I share with you my prepared remarks, I wanted to preface by highlighting five main takeaways. We're seeing the best year ever for our HSE 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, and our assets provide commodity optionality to position ourselves to benefit from relative movements in 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. 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 effort 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 in the third quarter, as you can see on slide four, 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 $1.04. 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 to $1.10 to $1.30, respectively. We delivered lower capital expenditures in the third quarter versus the second quarter. As noted on slide six, third quarter CapEx was in line with our interim 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. Our teams did an exceptional job turning all wells back on the line. Our 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 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 and 325,000 VOE 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're 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 targets, which you'll find on slide seven. We know you may have questions regarding the specific inputs of 2021, including rig counts, well counts, et cetera. As we're 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 are projecting 1.2 to 1.3 billion in capex in 2021. We're projecting a low single-digit production growth forecast year over year for 2021 with a cash flow break even of $32 WTI. We've talked about moderating growth for the past couple of years, and we have consistently stated it is imprudent 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, as we have been free cash flow positive since 2016. We expect to deliver significant organic free cash flow and are projecting approximately $400 million at $40 RTI 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 pay 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 focused on approaching $4 billion or below by year end 2022 or 2023, depending on commodity prices, we are ultimately projecting total debt of $2 to $3 billion. We believe this is to be part of a strong program of capital returns to shareholders. I will 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 oil-aided or gas-aided 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 hedged in 2021 with two-thirds representing collars with a weighted average floor of about 267 and a weighted average ceiling price of 344. 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 fundamentals warrant. Finally, I did want to highlight the latest update regarding a potential accelerator for debt pay down, which is a partial monetization of our water infrastructure assets. With strategic water infrastructure across the Bakken and Oklahoma, we believe our unique water opportunity is a differentiator. We have executed a non-binding term sheet with Sixth 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 in our water infrastructure assets. Proceeds of this pending transaction will be earmarked for accelerated debt reduction. We're currently working with 6th Street regarding definitive documents and are targeting consummation of the transaction later this year or early 2021. This debt reduction accelerator would be in addition to the organic debt reduction schedule I 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 a 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, a peer-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.
spk17: Thanks, Bill, and good morning, everyone. I want to start out by thanking our employees for their hard work and dedication that has 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 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 return to production during the third quarter. These third quarter wells are producing in line with expectations. I'll point out that 77% of the production from the new wells and scoop was oil. We've completed 52 wells in Oklahoma this year through the third quarter, primarily targeting the oil and condensate windows of Scoop. Approximately 90% of these wells are Woodford producers in springboard one, as we moved from the Springer to the Woodford reservoir in phase two of our row development. All totaled, we have completed 78 Woodford producers in springboard one, and as the chart on slide nine illustrates, the average Woodford well performance is tracking right on top of the type curve we 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 nine 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 one 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 multi-layered reservoirs, including the Woodford, Sycamore, and Springer reservoirs that are all proven. 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 in this area is oil weighted and the performance of the wells competes head to head with our springboard one and two 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 three and four areas. These charts include two Woodford and two Sycamore producers and 60 to 70 percent of the production is oil. Names and locations have been withheld for competitive reasons, but you can see these are outstanding producers. Current EURs for these wells range from about 1.5 to 2.5 million BOE per well. As we've seen in springboard one, our capital efficiencies will benefit greatly from the economy's scale as we develop these projects. A strength for our 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 as supplies predictably waned. 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 are 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 wells continue to clean up. These prolific gas-producing wells are benefiting from today's strong gas prices and are expected to deliver 50% rates of return at $3 gas. Given the current market dynamics, we anticipate natural gas prices will continue to strengthen in 2021 and 22, and we plan to keep our Oklahoma rigs focused on gas-weighted wells for the near future. Operationally, slide 8 shows that efficiencies have driven our completed well costs in the Bakken and Oklahoma down 14-24% respectively since 2018. The majority of the cost savings have occurred this year, and 70-80% 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 is driven by the structural changes in techniques and design that shaved another 3.4 days off of our drill times. Today, our routine spud to TD is 11 days and we believe we're on the track to achieve a $6.9 million total completed well cost in the near future. This is an all-in cost, including cool 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 stem crew in late November and two additional crews by early December. Company-wide, we expect up to 46 gross operated wells will be turned to production by year-end, all of which have been stimulated and are being prepared to flow. At year end, we expect to have approximately 140 ducts and 145 wells in progress. With that, we are ready to begin the Q&A section of our call, and I will turn the call back over to the operator.
spk11: We will now begin the question and answer session. To ask a question, you may press star then 1 on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then 2. Please limit yourself to one question and one follow-up. If you have further questions, you may re-enter the question queue. At this time, we will pause momentarily to assemble our roster. And our first question will come from Doug Legate of Bank of America. Please go ahead.
spk03: Good morning. This is John Abbott on for Doug Legate. Our first question is on the corporate break-even. And if we went back to your commentary during the second quarter, it seemed the cash flow break-even was in the upper 30s to low 40s. But when we look at your slide number seven, where you suggest that you can generate $200 million of free cash flow at 35, it seems that your break-even has fallen, let's say, maybe to 32. Could you explain sort of the change, you know, during, you know, between the second quarter and the third quarter? And is the lower sustainable break even sustainable on a multi-year basis?
spk15: I mean, the break even is a factor of the capital you choose to invest. We have a very low maintenance cost relative to peers. We have exceptionally well-performing assets. We're, you know, we're benefiting from higher gas prices as well on that portion of the streams. So we are... So as we look to 21, 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 at 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, you know, I think we're extremely well positioned, not only for next year, but for the balance of this year. You know, we've got a proven track history. $258 million of free cash flow in the third quarter is just an appetizer.
spk03: And then for our follow-up question, recognizing that you may be limited in what you can say, given that you just entered a non-binding agreement, do you still believe in the $1 billion value, 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 should we think about the impact to maybe OPEX or to your well cost from a partial sale?
spk16: Yeah, we're not, for 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 toward 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 some point in time. We'll be actually back at that kind of mid-cycle pricing and mid-cycle drilling activity. But right now, we're not able to share with you any of the details of the concept for obvious reasons.
spk15: 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 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 to debt, and that's going to be a significant and extremely beneficial impact.
spk03: Thank you very much, and I thought it was a good quarter. Thank you. Thank you.
spk11: The next question comes from Derek Whitfield of Stiefel. Please go ahead.
spk06: Thanks, and good morning, all. Hi, Derek. Morning. Well, 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. and your 2021 outlook. As I read and listen to your comments, it certainly projects a more balanced tone with the continued activity in the Bakken and a potential return to oil-weighted activity in Oklahoma in the second half. That to us implies a flat to modestly down oil profile. Is that a fair read?
spk16: We're really not given oil or 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. The oil, the fundamentals are not what we think they'll ultimately be. We've got a significant oil inventory that we will bring back home when the fundamentals start strengthening. And so if that strengthening happens in the beginning of the year, we'll shift to oil. If it starts happening later in the year, we'll begin. The gas is still strong. We shift into gas. And so the focus you see in there, is really cash flow focused. 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 have kept drilling oil. But from a cash flow optimization, from a capital efficiency, that makes no sense to do that. And so what you'll 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.
spk06: Great. And as my follow-up, I wanted to focus on basis fundamentals for Oklahoma. In addition to a strengthening Henry Hub price, Is it also reasonable to expect tighter diffs in light of recent pipeline additions and the declining associated gas profile?
spk16: 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 an expectation. We'll continue to see that type of strengthening. We've got Aaron Chang here as vice president of our marketing and might have Aaron comment also on the diffs in particular.
spk12: Yeah, Derek, I think for the reasons that you mentioned, we would expect 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 benefactor of the new pipeline coming in service earlier this year as well. And so that continued length and capacity relative to supply is going to continue to remain structural for differentials.
spk06: That's great. Very helpful. Thanks, guys. Thank you.
spk11: The next question comes from Brad Heffern of RBC Capital Markets. Please go ahead.
spk04: Hey, good morning, everyone. Just as another follow-on question on the water business, obviously I don't want to pin you down on it too much, but can you verify that the sort of debt targets and walk that you give on slide seven do not include the potential water sales?
spk16: Yeah, thanks for bringing that up, Brad. And I put it in the script, but I also wanted to appreciate you asking the question, because I do want to highlight that none of those slides, none of those projections of debt have included any of the contribution of a WaterCo assets being focused on reducing the debt level. We will, as I stated, we've earmarked those for reducing the debt. What you're seeing in that schedule that we've highlighted where we're going down to $4 billion of total debt and then going below that, it's all from our organic activities. None of that is from any type of dependency on the Water Co. And this will be an accelerator. So the proceeds we receive from Water Co. will reduce that even further and at a more rapid pace than what are on those slides.
spk04: Okay, thank you for that. And then on the Bakken, you know, 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've pursued more step-outs since then, and maybe just broader commentary on how you see the core inventory in the Bakken shaping up at this point.
spk17: Yeah, 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.
spk14: It's safe to say, though, that basically what we initially saw in our step outs has basically proven out across FOIA.
spk17: Yeah, that's a good point, Harold. You know, we are, I guess the main point of your question here is are we still pleased with the results we're seeing in these step-outs? And yes, we definitely are. And we see that as, you know, just continuing to be a growing part of our portfolio.
spk10: Okay. Thank you. The next question comes from Neil Dingman of Truist Securities.
spk11: Please go ahead.
spk02: Good morning, all. This is Nate Sensen on for Neil. Thanks for taking my questions. So my first question is with regards to your latest scoop acquisition. So it looks like the acquisition might be quite far south in the place. I'm wondering if you could just discuss your thoughts on that part of the scoop versus more central or northern areas of the place.
spk17: Well, yeah, it's, you know, you're correct in the sense it's a little bit further south, but, you know, what you're seeing down in this area is uh you know we're seeing more i guess i would say more oil weighted uh uh oil weighted uh performance from the wells down in this area i think uh you know those two or four wells that we showed you there are a great example of the type of performance we're seeing and as you get down south we're seeing that we have multiple reservoirs plus multiple zones within those reservoirs that we are targeting in the sycamore we have uh uh a couple targets in there that we have and also in the woodford it gets uh we also see the wood for thickening in this area and and uh 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 uh very uh I guess I'd say it's an area that we're pleased with and we're going to continue to build our position there.
spk02: That's super helpful. And for the follow-up, I'm just hoping you can provide your thoughts on the latest Dakota Access developments. So it seems like there was some incrementally negative press surrounding the oral arguments that took place in the D.C. Court for Appeals earlier this week. So I'm just wondering if your thoughts around the eventual outcome of that have changed at all.
spk16: Unfortunately, I think you broke up just a little bit. Would you mind repeating it, Nate?
spk02: Oh, yeah, 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 oral arguments in the D.C. Court of Appeals earlier this week. So just wondering if your thoughts have changed at all on that.
spk16: Yeah, on DAPL, hopefully you would have seen the transfers' comments yesterday, and a They came out feeling very strong that their legal case is still appropriate. They've got a strong case. Their position is rule of law will prevail in that they do not expect that DAPL will be shut down. Okay, great. Appreciate the commentary. Thanks, guys.
spk14: Thank you.
spk11: The next question comes from Arun Jayaram of JP Morgan. Please go ahead.
spk13: Yeah, good morning, gentlemen. I was wondering if you could shed a bit more light on what looks to be a pretty dynamic capital allocation program as we think about next year. And I know it's early. You haven't given us your official guide. I'm just trying to think about, as we look to model next year, how today you're thinking about capital allocation between the North and the South and where the where some of the capital that you're using on some of the gas opportunities, where is that being allocated from?
spk16: So if you look at the capital program we've got going on right now, we've got three rigs in the south and two in 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 may move some things around depending on what the commodity prices are doing. But we've been real pleased with our movement in May. And as everyone will recall, I'm sure the gas prices were in the $1.60 range or so at that point in time. And then we ended up moving a lot of rigs into the gas area to start accessing what we thought was going to be a stronger fundamentals on gas that's proven out. Offtake for gas, as Aaron Chang mentioned earlier, in Oklahoma is real strong. We've got flexibility and 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, you know, whether we're going to be drilling in the north or the south, but you could 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.
spk13: 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 6th Street here, but what are some of the broader objectives? Clearly debt reduction is something that you're thinking about, but what are some of the pushes and pulls as we think about you getting to the finish line in the agreement there?
spk15: It is a situation where we can't disclose any more than we have. We'll, you know, 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. They're 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, you know, 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. You know, once we achieve that, we'll come out with more information for you at that time.
spk16: So we intentionally put all the slides together that showed cash flow, showed debt reduction, without taking any credit for any type of water code transaction. Because, as you know, on any of these things, there's always a 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 an important one. And as John just mentioned, this will be an accelerator just to move more money into that and bring those debt targets ahead on our schedule.
spk15: Our cash flow generation and our debt reduction without doing anything on WaterCo are extremely impressive numbers. This is the fifth consecutive year that we've generated free cash flow. We've given you indications of 2021. Obviously, the cash flow yield on that is dramatic at the top end of a peer group. I mean, it competes across industries. and being able to do something with Waterco only accelerates and amplifies that, so 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 strong generation capacity with a deep inventory.
spk13: And that next year free cash flow guide is what, $400 million at 40, is that right?
spk15: Yeah, we gave you some ranges on that, $400 million at 40, $650 million at 45, $200 million at 35, a break-even of 32. We also did something we haven't done before, and we gave you a reinvestment range of 65% to 75%. So I think we've given you a lot of variables there. What we hope you glean from it is just what our capacity is and our ability. Our job is to generate regardless of commodity price, and we've got a proven history of being able to do that. Great.
spk08: Thanks a lot. And Arun and Rory, you can see some of those details and those figures that John provided on slide seven of the deck as well.
spk13: Yeah, I did catch that.
spk15: Slide seven, certainly one to focus on. Slide four, comparing to a broader group. Slide five, you know, the capital efficiency and cost leadership relative, and then slide seven, there's a lot in there to get your hands around. And, you know, it's all third-party data that's verifiable. It's very strong. Great, gentlemen.
spk13: Thank you for that. Thank you. Good to talk to you.
spk11: The next question comes from Brian Singer of Goldman Sachs. Please go ahead.
spk09: Thank you. Good morning. I wanted to ask on the production trajectory because there's, I think, a lot of moving pieces that you kind of talked to in your press release. It seems like there's a big step up coming here in the fourth quarter with the strong volumes that you're highlighting on the natural gas side in Oklahoma. And then you also talk about 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.
spk15: Yeah, we'll come out with a lot more on 21 in February. We did give you indications that we're projecting 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, a significant one, as 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 sizable 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 21, 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. I think we're set up well for 21.
spk16: The other point on the $250 million that Jack talked about that we're bringing on, we're ramping into that, so it's not an instantaneous $250 million to go into your calculus there.
spk09: 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 in terms of enhancing inventory either within the core or pushing out beyond the core of the core?
spk17: yeah thanks brian uh you know as we talked about before we do have some tests going on that are you know uh basically confirmations outside down south in the extension areas and we are pleased with the initial results we're seeing there but you know uh you know from from an inventory standpoint maybe we just step back and take a look at it just you know if you look at our inventory as a company and It's capable of growing our production at a 5% to 6% combined annual growth rate for the next 10 years. The inventory that we've got scheduled to achieve this growth over the first five years represents about a third of our inventory corporately and delivers a 30% to 50% rate of return at $40 and $50 WTI, respectively. you know uh you know and oil cut you know over these five years right now it seems like you could say the average around 55 so and this is a something i think really should be pointed out is that this is a well-defined inventory you know with proven reservoirs with demonstrated well density and it's not assumed there's you know this is our our assets are we know our assets well as you saw you know uh from just say the results in in our uh springboard one area i mean a year ago we predicted and anticipated the performance of the woodford wells and you could see how there's great follow-through there so point there is that we really uh 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 in a lot of ways of our inventory from others uh, in the fact that it is very well known and that's why our performance year, year over year and quarter over quarter from our assets, uh, is, is very, very repeatable. Uh, so, and predictable in our, in our, you know, our production performance guidance and also, and obviously in our cashflow. So anyways, uh, I, I just think that that maybe gives you a better, broader perspective of our inventory and, and, uh, You know, in Oklahoma, I have to say, you know, we added on this nice bolt-on acquisition. We've always said in times like these, we find that this is an opportune time for us to grow, and we'd like to do it through bolt-ons, and obviously we've done that here this quarter. We also added some smaller bolt-on earlier this year, you know, in over and above this area. You know, this acquisition we mentioned here of 19,500, we've actually in Oklahoma put almost that much more acreage, basically doubled that 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 And we see that as just the opportunities that 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.
spk10: Thank you. The next question comes from Joseph McKay of Wells Fargo. Please go ahead.
spk05: Hey guys, this is Joe on for netting. I know we got some thoughts around the election on the opening remarks, but could you just give a little more detail around how you're thinking about, you know, the outlook for the regulatory environment moving forward, given what we know right now?
spk14: Yeah, you know, that's, you know, the way that them sometimes like to play, you know, during the last administration, Obama's administration, We've suffered death by a thousand cuts. We were able to survive it, but fight them off with the legislation and hold them off the best we can. Thank goodness, it looks like we're gonna control the Senate, add to the House representation. That's the game we'll be playing again, to hold them at bay. We'll have a work cut out if it goes that way, but we're used to playing that game, and it'll be up to us again to do that again. The good thing about it is, like I talked about earlier, I think everybody, very strong support turned out because of the fact that the Democrats, you know, want to end oil and gas. Nobody wants to do that. Everybody realizes that this is very, very important. The Commonwealth is lucky. We have very low federal exposure, you know, less than 7% or something close to that. And so, you know, we're not going to be fighting the game, fighting the problem like other people might be. But anyway, that's the way I see it. Good question. Thank you.
spk05: 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 NGLs?
spk16: The question was how do we see NGLs? Was that the question?
spk12: Yes. Yeah, 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 in our NGL pricing and realizations as we move into the third quarter, and we'd expect it to continue to increase through the end of the year and into 2021.
spk14: We're about a third of NGLs with the gas frame in Oklahoma, is that correct? Correct.
spk15: Our acreage position in Oklahoma is about a third condensate, a third dry gas, and a third oil. That condensate is a very rich condensate, so 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 optionalities we talked about on the call.
spk14: Thank you.
spk11: The next question comes from Jeanne Way of Barclays. Please go ahead.
spk01: Hi. Good morning, everyone. This is Jeanne Way. Thanks for taking my questions. So my question is really just on slide 10, and we saw the disclosure on Springboard 3 and Springboard 4, and we are wondering maybe if you could talk a little more broadly about any quality differences between springboard one and then the subsequent springboards in terms of oil cut and consistency. Um, 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.
spk17: Right. Um, well, I think what you can see there is a type curve we've got on, you know, slide 10 comes directly from springboard one and you can see these wells performing right in line actually of outperforming that curve. And, uh, so as far as any differences and 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 the 1.5 that's a unit curve so you'd expect these wells maybe to produce a bit more but these are really outperforming that that unit type curve by a significant margin and so we're very pleased with the results and i think it has to do with you know reservoir quality in in this area and uh So, but all of these areas are just, I mean, very good performing areas. We have no concerns at all and, in fact, are very pleased with this and pleased that, you know, combined we've managed to put together about 40,000 additional acres in these areas pretty much under the radar during the last year.
spk01: Okay, great. Thank you very much.
spk17: Thank you.
spk11: The next question comes from Noel Parks of Coker and Palmer. Please go ahead.
spk07: Good morning. Hello. Good morning. I was interested in hearing a little bit more about the bolt-on acquisition you did in the scoop in Springer. And just curious about the acreage that you bought, how long had the prior owner you know, been in the play and I was just curious whether they had been actively drilling or had sort of, or had sort of neglected the acreage. And I was also wondering if, since you said it's right in proximity to stuff you already hold, I was wondering if this was 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 time frame. So it was real familiar acreage to you, in other words?
spk14: Well, I'll speak to that. Now, this is a player that's been 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.
spk07: And so it is... Have they been actively working it or had they, you know, had capital constraints and so forth?
spk14: No, they're an active player.
spk07: Oh, they 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 up front or did it take you a while to sort of hit the bid ask on it? on the ultimate price.
spk14: It's something we've dealt with a long time, and so, you know, normal process. Thank you.
spk07: Okay. I guess just what I'm trying to get at a little bit is, you know, we've all been talking about the obvious case for consolidation for so long, 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?
spk16: Well, we've been active in the area for a while, so this is a combination of acreage from a player plus other players, 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 this group. 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. 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. It's not something that just happened over the last month or since all the merger activities.
spk17: Yeah, 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.
spk16: Yeah, 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 strength of the company. We built this company on organic development. That's who we are. We have really good capabilities in that space. And so we're always looking with our geoscience 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.
spk14: And it takes minimal integration to make it happen.
spk17: Right, it dovetails right into our existing operations, day one.
spk11: This concludes our question and answer session. I would like to turn the conference back over to Rory Sabino for any closing remarks.
spk08: Thank you again for everyone joining us today. Please reach out to the IR team with any additional questions. I would like to turn the call over to Mr. Hamm for some closing remarks.
spk14: Yeah, thanks, Rory. My hot hat is off to Bill and his team for their great execution in returning 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.
spk11: The conference is now concluded. Thank you for attending today's presentation, and you may now disconnect.
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