Good day, ladies and gentlemen, and welcome to the First Quarter 2020 Continental Resources Incorporated Earnings Conference Call. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. 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, sir.

Good morning and thank you for joining us. I would like to welcome you to today’s earnings call. We’ll start today’s call with remarks from Harold Hamm, Executive Chairman; and Bill Berry, Chief Executive Officer. Other members of management will be available for Q&A, including: Jack Stack, President and Chief Operating Officer; and John Hart, Chief Financial Officer. 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 in 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 has been posted on the company’s website at www.clr.com. With that, I’ll turn the call over to Mr. Hamm. Harold?

Good morning and thank you for joining our first quarter earnings call. In response to the unprecedented times we are facing, Continental has taken consistent and proactive steps to ensure that we are preserving value over volumes. We’re using this downturn to refine our operational efficiencies further. When we provided our original budget in February, we were already forecasting a fundamentally oversupplied market in the first half of the year, so we reduced our pace of growth to deliver a disciplined approach to value creation. Then, in March, we were hit by demand disruption attributable to COVID-19 as well as the dumping actions of Saudi Arabia and Russia. Thanks to our highly skilled operations team, the optionality of our portfolio, and our predominantly held by production acreage position, Continental quickly responded as the first mover in adjusting our plans for 2020. We reduced spending by 55% versus our original budget. In response to the unprecedentedly low prices, we began voluntarily curtailing operated oil production across the Bakken and Oklahoma and are curtailing up to 70% in May. Our internal supply and demand model is consistent with the external models that see a significant reduction in production due to decreased capital expenditures and worldwide curtailment. As is evident from recent peer earnings reporting and commentary, the US oil and gas industry, coupled with the supply cuts coming out of OPEC+, is starting to curb production so as not to overwhelm storage capacity. We’re also seeing the easing of stay-at-home orders across the globe as economies get back to work, as we have here in Oklahoma, which we believe will lead to increased demand for petroleum products. The Saudis, despite recent efforts and having taken steps in the right direction, have needed to do more, with recent demand estimates down more than 30%. Their announcement this morning validates this and highlights the demand slump. It is important that the US oil and gas industry, as well as other global producers, continue exerting capital discipline to avoid overproduction and oversupply during these times. Everyone needs to continue to cut back and participate as the slump continues. UAE and Kuwait are examples of this. Our models show that the market began balancing by mid-year and predicts that 2021 will be strong and 2020 will be even stronger. We are already beginning to see the consequences of the supply and demand rebalance manifest in current and future prices. I know that you would prefer that formula from our model as to how we ramp up production over the next few months. We believe it’s best for the company to remain flexible as the market recovers. We also know from experience that we can quickly bring this deferred production back online once market conditions improve, and we will not see degradation in reservoir performance as wells are brought online. We’re doing our part to responsibly preserve our high-quality assets and shareholder capital as a leader in this industry. Bill will provide more details about this later on the call. Finally, I’m thankful for President Trump’s leadership in the midst of these volatile market conditions. While it’s unlikely the Saudis will flood the market like this again anytime soon, I believe this recent downturn has highlighted to the federal government just how important US shale producers and the preservation of the American Energy Renaissance are to the US economy, jobs, and to our national security. I would now like to turn the call over to Bill, who will provide more details regarding our priorities and outlook in this current environment.

Thank you, Harold, and good morning, everyone. In 2020, Continental has continued to demonstrate its commitment to the responsible stewardship of our assets and shareholder capital. As Harold mentioned, we are proactively preserving shareholder value over volume. Referring to slide 3, our priorities include: protecting our balance sheet, preserving cash flow, conserving our world-class assets for improved market conditions, and delivering capital-efficient operations. With strong portfolio optionality and liquidity, we plan to be well-positioned for when market conditions improve. Continental has a strong track record of preserving shareholder value. Thanks to the strength of our assets and the capital and operating efficiency of our teams, we are the lowest cost producer among our oil-weighted peers. Referring to slide 4, our drill bit F&D cost, operating WTI breakeven price, and cash costs are consistently highlighted as peer-leading by the investment community. We delivered another solid operational quarter as our assets continue to deliver strong outperformance. First quarter production exceeded both our internal and analyst expectations, averaging over 360,000 Boe per day and over 200,000 barrels of oil per day. Referring to slides 5 and 6, our teams delivered consistent and capital-efficient results from our deep inventory set in the Bakken and Oklahoma. Production expenses per Boe of $3.61 and DD&A per Boe of $16.35 were both well within our previously issued guidance range for the year. Total G&A at $1.31 and cash G&A at $0.81 were materially better than previously issued guidance. We spent $650 million in non-acquisition CapEx in the first quarter. This is over half of the previously revised CapEx budget of $1.2 billion, which is a 55% reduction from our original guidance. The remaining $550 million in CapEx will be spent over the next three quarters, and we are already seeing the potential for costs to trend even lower. At current strip, we are targeting to be cash flow positive in the second half of the year. We continue to demonstrate a strong commitment to our balance sheet, having reduced our net debt over $1.7 billion over the last four years. Included in this amount is $139 million of principal that we repurchased and retired from late March to early April. These bonds were repurchased at a steep weighted average discount to par of 53%. With no imminent maturities and a borrowing base redetermination, as well as an unsecured credit facility, we have a strong liquidity position. Harold mentioned we are minimizing volumes by curtailing 70% of our operated oil production base in May, which represents about 60% of our total Boe base. I want to make it clear that all of this production is cash flow positive at today’s prices. I’d like to further highlight the depth of Continental’s flexibility and optionality to preserve value. In anticipation of the possibility of a continuation of an oversupplied market, we have refrained from entering any oil sales agreements in June. In June, we intend to continue curtailing our oil production selectively, targeting sales that maximize our natural gas production to take advantage of the momentum in natural gas prices. This enables us to have the flexibility, consistent with our plans, to defer our production for a more stabilized, constructive, and higher-priced market that we anticipate is imminent. Referring to slide 7, I highlighted a 55% reduction in capital spend from our original guidance. We will also reduce our rig count by over 80% from the beginning of the year. We have dropped our expectations for rig utilizations from about 20 rigs to four rigs by year-end 2020. We have zero stim crews running in the Bakken and expect to average one stim crew in the South for the remainder of 2020. We suspended our quarterly dividend and are prioritizing liquidity and debt reduction. While we repurchased 8.1 million shares in the first quarter at an average price of $15.60 per share, representing more than 2% of our shares outstanding, we have now suspended our share repurchase program. We have minimal long-term service commitments, and the majority of our acreage is held by production. As the current price environment remains dynamic, given market uncertainty caused by COVID-19, the company has decided to withdraw its previously issued guidance for 2020 and suspend further guidance. We will reassess issuing new guidance as market conditions continue to evolve. In closing, I want to take a few moments to acknowledge and thank all of our employees and team members, especially those in the field, for their continued commitment to safety and operational excellence during these unprecedented times. Our teams have demonstrated exceptional nimbleness in responding to changes in capital and production targets and continue to deliver exceptional capital efficiency and cost savings across all operations. The COVID-19-related risks, restrictions, and limitations placed on each of our team members and their families put a great deal of stress on each and every one of them, yet the team continued to deliver outstanding performance across every part of the organization. My sincere compliments and deep admiration go to each and every one. I can’t imagine a more committed and capable team than the Continental Resources team, and I’m proud to be a part of it. With that, we’re ready to begin the Q&A session of our call and we’ll turn the call back over to the operator.

Thank you. We will now begin the question-and-answer session. Our first question today will come from Arun Jayaram. Please go ahead.

Yeah. Good morning. I wanted to get your views, perhaps for John, on what sustaining capital looks like today from a D&C and total perspective for the - I was wondering if you could give us some color on the Bakken versus the South?

Are you asking about maintenance capital?

That’s correct.

Okay. So the fourth quarter - we’ve pretty much talked about maintenance capital just about every quarter. It’s a very fair question. So if you look fourth quarter to first quarter, those are the production levels that we’re at. They’re out there now. So they’re pretty consistent. We’ve talked in the past about a maintenance capital for D&C being in the $1.5 billion to $2 billion range. We’ve always been very much straight down the middle of the fairway. I’ve seen a lot of questions from a lot of companies. And some of them look at it differently, some of them factor in a lot of DUCs, some of them factor in lower levels of production. I think, just being consistent, not applying the benefit of DUCs, not applying some of the other things that some others do, just in normal course, we could hold in that $1.5 billion to $2 billion for several years and hold flat off the fourth quarter and the first quarter in those numbers. If we were to apply DUCs or we were to do some of the other things, we could reduce that number lower for year one, certainly. And, additionally, as we’re going forward, we’re continuing to reap efficiencies and additional cost benefits. And I can see that going even further down with those types of things factored in. But just to be right down the middle of the fairway, I’d say $1.5 billion to $2 billion.

Great. And just my follow-up, John, the cash balance did rise in the quarter. So I was wondering if you could broadly talk about the balance sheet management in the downturn. And it looks like you did tap on the facility, but I just wanted to get your thoughts on just managing the balance sheet overall.

Yeah. Certainly. Thank you, Arun. Obviously, we’ve done a lot of things from a cost savings perspective. You’ve seen reductions in G&A from what was already a remarkably low G&A; $0.81 on cash G&A in the first quarter. So we’re very strong in those categories. Going into the corona - and our banks are very strong. Our credit facility is strong. We don’t have covenants really in there, debt-to-capital covenants; only one we have, and we’re well south below that and we’re not in any realm of even approaching that. Our debt would have to go up by $8 billion to hit that covenant level. So I told you we’ve got a lot of cushion. But going into the virus, with everyone moving to remote work, with banks moving to remote work just with concerns that with how would this work? Because none of us have ever dealt with these types of things before the virus I’m speaking to, we decided to go ahead and have a little bit of cash on hand just ahead of time just to make sure that if there were a hiccup in the systems in drawing cash, with debt payments and other things, and interest payments coming due that we would have that cash in hand. So we’re probably maybe overly cautious, but we wanted to make sure there weren’t any hiccups in the system. So we did access a bit.

Okay, thanks a lot...

Obviously, we’ve got a very large new revolver with a lot of liquidity.

Great. Makes a lot of sense. Thanks a lot.

Thanks, Arun. Good talking to you.

Our next question will come from Brad Heffern with RBC Capital Markets. Please go ahead.

Hey. Good morning, everyone.

Hey, Brad.

A question on the shut-ins. So you talked in the prepared comments about how all the wells that are shut in are still cash flow positive. And so, I’m curious if the shut-ins are really just supply/demand related or if there is some sort of price component where you’re looking for a certain price to sell the oil at? And so, is there a chance that we could see the shut-ins linger even if we do see a recovery in crude more than we have already?

Yeah. Thanks, Brad, a good question. What we’ve been doing internally is a lot of analysis based on optimizing the combination of cash flow, present value, and debt repayment. And everything we’ve been doing is orchestrated in that effort. If you look at the way we view the world, it’s been a clearly destabilized world. The supply side has been destabilized. We’re seeing that starting to correct. Obviously, with COVID-19, the demand side was significantly destabilized. We’re starting to see that come out. And on top of that, we’re seeing the market pricing mechanism with the Merc going negative also in a destabilized world. So with those three destabilizing factors, we’ve taken the position that we’ll manage this in a very deliberate approach, taking a look at when we want to put our volumes back on. Clearly, from a contango point of view and from a fundamental point of view, you can analyze this and say, yes, you should look to at some point bring production back on. You should probably look at doing that imminently, as I’ve said in my comments. At the same time, as you see that contango start to shift a little bit, you’ll start to see - and doing that from the fundamental analysis, you’ll start to see us probably legging back into the - bringing production back on.

Okay. Thank you for that. And then I guess as far as cadence for the rest of the year goes, you talked about still one stimulation crew in Oklahoma. You said there are no Bakken crews currently. Should we assume that that’s the case for the rest of the year, or is there a chance that potentially Bakken completions come back at some point? Thanks.

Yeah, we’re not going to provide that level of guidance at this point in time, Brad. But the spend rate, which is the cadence you’re looking at, is a little bit faster in the second quarter than the third and the fourth, but not a whole lot of difference between the quarters. We’re going to make a judgment call month by month and take a look at what the fundamentals are looking at doing, and then making that determination as to when we start bringing the stim crews back in.

Okay.

Recall, Brad, we mentioned that we’re actually below our $1.2 billion budget also. So there’s flexibility.

Okay. Thank you.

The next question will come from Doug Leggate with Bank of America. Please go ahead.

Thanks. Good morning, everybody. John, I hate to beat on the maintenance capital question, but I wonder if I could just ask you to clarify when you talk about sustaining capital. I guess you were talking about fourth quarter 2019, first quarter 2020. What do you think the exit rate looks like in exiting 2020, if you like? And I’m really curious what that maintenance capital looks like. And, I guess, if I could just clarify a little further, do you preserve the production capacity by shutting in the production, so essentially they’re both the same number? I guess I’m looking for the exit rate on the sustaining capital that goes along with that.

You’ve got a lot in there, Doug. So, obviously, we retracted guidance for the year. We recognize that you would like more color on that. Let us get back to the markets that we talked about and bringing production back on, and we’ll give you additional clarity on the balance of the year here as we go forward. Obviously, if you’re not completing and you got normal declines when you’re producing, your production would come off a little bit with the efficiencies and cost savings that we talked about. That maintenance capital number I would expect to go down some. It might still be within the range we’ve given towards the lower end; it might be below that end. If we factor things such as DUCs and other things in, it could be remarkably lower than that. So there’s a lot of flexibility there. We feel good about where we’re at. We’ll give you more color on exit rates and fourth quarter production as we see the cadence of bringing production back on. From a reservoir perspective, I think that was the last part of your question. Look, we’ve dealt with weather and other things in the Bakken for well over a decade. Our experience and our history in the plays we’re in shows us there’s no impact from shutting in production. So we don’t expect to have any impact whatsoever. So, yes, we’re preserving production capacity into what we believe will be an imminently better commodity price.

So to be clear then, exiting 2020, we should still think of about $1.5 billion to $2 billion as a sustaining capital number?

I would say I think it could be lower, but let’s see where the exit rate is. And when we guide you on that, we’ll update that maintenance capital for you as well.

Good. I know we’re not pretending there’s any precision here, so I appreciate the answer. My follow-up, if I may...

Yeah. We’ve always tried to be transparent there and open. But, obviously, we need to see how this plays out a little bit to make sure we’re giving you good guidance.

Understand completely. My follow-up, if I may, is probably for Harold, but John you might want to chime in here as well. And it’s really about the go-forward business model for Continental. And, Harold, if I could just preview this a little bit. I mean, you’ve been very vocalized, as a lot of people, about Saudis dumping oil and all the rest of it. But if we take a step back, you guys may have some of the lowest cost assets in the industry without any shred of a doubt, but not everybody does. And the US as a whole increased by 50% from September 2017 when Saudi started supporting the price. So you could argue that in a free market, they’ll really just be saying we’re not going to subsidize the US shale model anymore. So I’d really like your response as to why you see this as a dumping issue and not, I guess, overenthusiastic or in the words of the Texas Railroad Commission, wasteful production given the growth we’ve had since September 2017. Coming out the other side of this, what does Continental's strategy look like? And I’ll leave it there. Thanks.

Certainly, it was a dumping issue. They picked a most atrocious time to try to do that. But when they made their announcement of discounting oil into the market from Friday to Monday, the price went down 30% in May 9 to May 10. So it was a dumping issue. I don’t think they’ll do this again, but you never know if they have a dose that they would have on the end that if this doesn’t work. They increased their production altogether by about 3 million barrels, and you can see the result of that with what’s floating on the water. So a lot of it out there. But there are a lot of reasons they can’t do this in the future, and we’re not going to be protecting them militarily and have them try to take this industry down and hurt national security in the future.

So, Doug, follow-up on your strategy going forward, really good question. I think what you’re going to see is the whole industry in the United States starting to take a different approach, and I think you’ve seen that with a lot of the comments that have been out in this quarter’s report. You saw us last quarter go out and say, we’re not going to overproduce and then oversupply the market, and we took a very strong position. For that effect, we continued that position. Now, I think what we’re seeing in the industry is the future business model is market share is going to be an important issue, and the market share capture rate that the US was pursuing in the past was probably not sustainable and I think that’s what happened here recently. So I would expect to see those growth rates attenuate in the US over the next few years.

Any thoughts on what that means for Continental?

Well, we established what we thought we would do this year. And then you saw the resource base we have has the capacity to deliver much more, but we’re not going to be providing guidance at this point in time as for those growth rates.

Appreciate it.

Go ahead, Harold.

I think to Bill’s point, everybody kind of felt - I don’t know if they were shocked a little bit by the percentage of growth and low percentage of growth that we put forth at the beginning of the year, but everybody - all the other operators out there have basically come back around to those numbers. So we weren’t far off in what we did.

Guys, I appreciate the answers. And I hope you all are doing well out there. Thank you.

Thanks, Doug.

Thank you.

Stay well.

Our next question will come from Derrick Whitfield with Stifel. Please go ahead.

Thanks. Good morning, all.

Good morning.

Good morning.

Regarding your voluntary curtailments for April and May, I wanted to see if you could speak to your curtailment strategy more broadly in terms of approach and well selection. Regarding approach, I’m really focused on whether you are pursuing full shut-ins or simply pinching back on wells?

Yeah, we’ve got an internal model that we use to help guide us on this, and it’s a well-by-well pretty granular analysis looking at everything from operating costs and GORs to the differentials, and that’s what we’re using to determine what we end up curtailing or shutting. Most of the time, it was in a full shut-in just because that’s managing your operating costs in the most efficient manner, but not always. Jack, I don’t know whether you have anything else you want to add to that?

No, there isn’t.

And as a follow-on question, could you comment on your views on the economic conditions required to return wells to production? I imagine it’s a function of the future curve, but there are also some differentials at play as well.

Yeah. It’s more to the fundamentals and the three things that I mentioned earlier. We clearly had a destabilized supply market and we’re seeing those fundamentals changing. We clearly had a destabilized demand side, and we’re seeing that change. The destabilization that was caused by the Merc allowing the WTI to go negative has put a pretty big shadow over all of us as to how we go forward with the nominations and the commitments of volumes. You guys probably understand that, and I’m sure everybody has run the numbers, but for each and every producer in the United States that sold on WTI, the April price impact of the average price of April was probably a $2 to $3 reduction for every barrel sold in April as a result of the negative number that we saw on WTI. We see now that there’s 5 million barrels more in storage in Cushing than there were then. So, there’s an even tighter storage market. I think we're going to continue to watch it closely to see if that destabilization, the market pricing mechanism continues or not.

Thanks, guys. Very helpful.

Thanks, Derrick.

Our next question will come from Jeanine Wai with Barclays. Please go ahead.

Hi. Good morning or afternoon, everyone. This is Jeanine Wai.

Hello.

My first question...

Good morning.

Hi, good morning. Thanks for taking my question. My first question is on capital efficiency. From the presentation, it looks like there’s a meaningful increase in capital efficiency in the SpringBoard anticipated for this year and a slight improvement in the Bakken. So maybe just wondering, can you provide a little bit more color on this and how much of this improvement you think is sustainable if we see a price recovery.

Well, thanks for the question, Jeanine. This is Jack. And, yeah, you’re referring to slides 5 and 6 in the deck here. I’ll start with slide 5 in the Bakken there and I’ll start off with a chart right on the top there to emphasize just the strong repeatable results we continue to get from the Bakken. I think that’s just an amazing chart. You see basically three years, plus another quarter, our first quarter here in 2020, and you can see how these wells are performing basically right in line with each other over that period of time. It’s just a remarkable repeatability, and that’s what we love about the Bakken is its dependable performance. To try to put some perspective on how these cost efficiencies are contributing also to the capital efficiency of the play, we’ve come up with this metric that you see on the bottom right-hand chart that basically shows you the barrels produced in the first 12 months for every $1,000 spent. You can see it’s about a 12% increase over that three-year period. A lot of people think that, as time goes on, your capital efficiencies are going to decrease and, in fact, they continue to increase. It’s pretty impressive considering that we’re in the middle innings in the Bakken as opposed to early innings. Now, if you go to page 6, you look at, say, SpringBoard, here in your early innings. Again, on the top-right chart, you see SpringBoard complete well cost reductions of about 24%, but we’re also seeing drilling cost efficiencies and facilities. There are many things going into this. But when you get to the bottom chart, you can see that’s about a 76% increase. You’re exactly right. There’s a more significant increase in SpringBoard, and that’s just a result of the efficiency gains that we’re making operationally across the play, combined with the excellent performance of the rock. You’ve got to have good rock, for starters. These reflect the capital efficiencies coming from our operations. Overall, I think, again, it just shows the strength of the assets themselves and the excellence of our operating teams on how they’re bringing these barrels to market.

Okay, great. Thank you for the comprehensive answer. Those charts are really helpful. Also, my follow-up question, maybe following up on Doug’s question, but pointing it a little bit more towards the dividend. Assuming that we do see a price recovery, does the dividend suspension lend itself to just a more conservative approach to capital spending going forward, so that you can accelerate maybe reinstating that dividend?

The dividend was suspended along with other reductions we’ve made in G&A and other things to preserve cash in this low environment. Liquidity and cash are the most important things. So that was a component of that. We didn’t eliminate it; we suspended it. So that is something the board can review in the future. Ultimately, that’s a board decision and I would be getting ahead of them to speculate one way or the other, so I’ll defer on that. We have a lot of optionality, obviously.

Okay. Thank you for taking my question.

Anytime. Thank you.

Thanks, Jeanine.

And our next question will come from Neal Dingmann with SunTrust. Please go ahead.

Good morning, all. My first question for John or Jack, I’m just wondering - this has kind of been asked, I want to see if I could tackle this a different way - wondering how you all view future priorities of your free cash flow including potential stock buybacks, debt repayment, reinstated dividend or organic or external growth? Because if I recall, not so long ago you would have placed stock repurchase towards the top of the list, it looked like you had done that throughout the first quarter. So I’m just wondering how you view the progress now.

Yeah. We did that January, February - early February - we haven’t done - so we’re not there now. I would say today it’s debt reduction. You saw that we bought bonds at a discount of $0.53 on $1. They’re trading a lot lower than that. But, in doing that, in essence, we eliminated $65 million of total debt since we bought them at a discount. If that opportunity presents itself again, I would say, we’ll evaluate that. Right now, liquidity preservation and reducing debt would be at the forefront of all of those items.

Thanks, John. And my second question for Jack. I was just wondering, Jack - you touched on this also a little bit earlier - could you talk a little bit about, I’m just kind of curious, from a broader standpoint, with the more minimal activity at least potentially for the rest of the year, how you would go about attacking the larger SpringBoard and Long Creek projects with just having the minimal activity potentially on each?

Right. Well, both those places, I mean, the assets aren’t going anywhere. With the reduced rig count, of course, we’ll see this develop at a little bit slower pace. But when you take a look at, for instance, in Long Creek, we’ve got about 20% of the 56 wells we plan to drill in there have been drilled and with facilities in place. They’re really basically ready to begin production once we decide to go ahead and stimulate the well. So Long Creek is in good shape, and these wells are in particular areas of the unit where we don’t have to develop this whole unit all at one time. This is, I guess, you could say maybe Phase 1 of Long Creek, given the lower pace of drilling now. SpringBoard, development, of course, will proceed more slowly as a result of the rig count reduction. But, again, these assets aren’t going anywhere. They’re as strong as ever and we’ll bring them on as it makes sense.

No, makes sense. Thanks, guys.

Thanks, Neal.

And our next question will come from Brian Singer with Goldman Sachs. Please go ahead.

Thank you and good morning.

Hey, Brian.

The original CapEx plan that you talked about on the last call, I believe, had a lot of wells that were coming on later in 2020 or in 2021. And I believe the budget, the original budget, had something like $700 million for wells that wouldn’t come online until 2021. In your current revised plan, can you talk about how we should think about the lag between when investment does start to ramp up and when we would see the impact either on growth or on mitigating declines?

Three to six months after that. You can look back historically over us; once we start applying capital, we’re on larger pads and we’re doing big developments, it doesn’t come on immediately. But once we start bringing those on, you’re bringing on large volume. I would say it’s a fairly quick and robust ability to adapt and bring that on, but it’s three to six months probably towards the longer end of that cycle, just depending on the size of pad, where we’re at in the stage of it, whether we have to drill or whether it’s already drilled, all of those types of things. So something’s already drilled and it’s completing, it’s quicker in there. It fits well into the contango market and it fits well into our views of the market. We don't just fixate on spot prices, as we’re looking at longer-term values and the ability to enhance shareholder value.

Great. Thanks. And then my follow-up is - and I’m going to take a shot at it, but I don’t know whether it will be successful - any ability to comment on where you see your DUCs at year-end based on your current plan? And then of the cost and efficiencies that you’re seeing, can you try to possibly quantify that and what could be cyclical versus what is secular?

Yeah, Brian, I’d say that we’re probably going to be in about 150 wells in progress at year-end in that range. Last year, we’re probably about 200, 215 wells, I think, was the number. So for comparisons, there you go. Your second part of the question was...

Cost efficiencies.

Yeah. The cost efficiencies, we talked about this even before the call just to verify, but we’re looking at cost efficiencies that are dominantly structural at this point. I’d say probably in the range of 90%, Pat, would you say, 80%-90% are going to be sustainable and structural going forward.

Yeah, Jack. And this is Patrick Bent. I think that is correct. I think 90%-plus are structural in nature. We’ve done a really good job in terms of our pricing and contracting new pricing. That touched close to the bottom. The vast majority of what we’ve been able to gain are structural in nature, so technical advancements, operational advancements, reduction in non-productive time. So, again, the 90% structural is a good number.

I think, Brian, in these times, our teams are just - they aren’t leaving any stone unturned looking for ways that they can continue to improve the efficiencies in the field. The things we’ve been going through with them here in the last few weeks are really quite impressive. We’re drilling some wells. We do have some rigs in the area. We’re setting records right now with some of the wells we’re drilling and just because of the efficiencies and downtime elimination, etc. The team has been able to do. As the last time, we are going to come out of this downturn stronger and more efficient than we went in.

Thank you.

Yeah, I’m going to repeat Jack’s last comment for emphasis. It is significant, the amount of benefit we’re gaining from this pause in activity, so to speak, to able to look back at our engineering and look at the activities we’re doing both from geoscience and from the technical engineering side and reconfiguring a lot of our activities. We’re seeing that already manifest itself in savings that Jack’s talking about. We saw a stimulation that - we probably cut 30% out of their cost stimulation just by redesign. The benefit came from having time to actually pause and take a look at it, because we were running so fast with all the activities we had going on. This gave us a chance to kind of sit and look at some of the data and understand it a little better.

Thank you very much.

Our next question will come from Noel Parks with Coker & Palmer. Please go ahead.

Good morning.

Good morning.

Good morning.

I was hoping you could catch us up on your gas marketing arrangements. I was wondering if you had anything heading out into the future that you were working on earlier in the year before everything hit with oil prices. And if you could also just refresh us on where you stand on some of those early arrangements that were put in place in anticipation of LNG?

Yeah. We don’t have any gas that’s going specifically to an LNG contract we’re selling into the market. We’re about 800 million a day is what we’re flowing right now in gas. So quite a bit of gas, a lot of it from the South, obviously, with the transportation benefit that we have here in the South.

Great. And, I mean, just with - as you look ahead to when you start ramping up activity again. Just based on the varying product mix across the different areas of the Mid-Con, are there any particular areas that would be heading up higher in the priority list if we assume that the improvement we see in gas actually does get sustained?

No, I don’t think there’s any area in particular. Our areas in STACK and SCOOP in particular are really - their being in Oklahoma, you have Midship coming on. I’m just speaking to the dynamic that could influence prices and actually improve prices is, just with Midship coming on, there’s going to be a lot of gas being taken out of the Mid-Continent region. It could actually provide an uplift in basically the price for us here because we’re not on Midship. Other than that, we’re pretty much business as usual.

Okay, great. And just to sort of follow-up, by virtue of what’s going on as far as the service cost component of your AFEs. We have heard a lot about vendors looking, even in this environment where there’s not a lot of activity looking to continue to cut prices more. Just wondering, do you have a sense of whether the drilling cost and the completion cost from the vendor side are kind of heading down proportionately? And in the event of a rebound, do you think those would also kind of go up proportionately, or do you think you could sustain better savings on the rig side maybe as opposed to the frac side?

No. I think we mentioned a little bit earlier when you look at the cost savings that we’re able to generate currently, 90% of that is structural which would leave the other 10%, plus minus, subject to pricing. There’s that small variability associated with the pricing aspect of it whether it moves down a percent or two or up a percent or two. Really, the key is, the savings that we’ve been able to generate are structural in nature through our technical teams.

Great. Thanks.

Noel.

Our next question will come from Nitin Kumar with Wells Fargo. Please go ahead.

Good afternoon, gentlemen, and thank you for taking my question. I guess my first question - I know this has been addressed a little bit. But slide 4, you show some very strong cost efficiencies compared to the peers. You’ve also taken probably what is the biggest curtailment that we’ve heard of so far this earnings season. Do your costs allow you to come back to work a little bit earlier? I mean, I’m just trying to understand what are your gating factors for bringing back this volume?

Yeah. So clearly when you see that cost structure like that, that suggests that - and anyone else, most of the other companies that are producing, they’re producing at higher cost. If they’re producing cash flow positive at those costs, we clearly would be producing cash flow positive at these costs. It gets back to the earlier comment that we made. We see that there were three fundamental pieces that were destabilized, and we took our production off of that. If you go back to the production we had in April, we would’ve actually preferred to reduce that production even further, but we had nominations and commitments to the buyers that we ended up delivering to. What we’re looking for is that fundamental strengthening, and we’re starting to see signs of it. That’s why we believe the pricing is going to imminently start strengthening as a result of the fundamentals on both the supply and demand side.

If I can get a clarification. I think I heard you say that you were not taking any nominations right now. Does that mean for June or is that for May?

For June. We are already committed with the nominations in May.

And our next question will come from Paul Cheng with Scotia. Please go ahead.

Thank you. Good morning, gentlemen.

Hello.

I think that the first one - hi. Can you hear me?

Yeah. Thanks, Paul.

Hi. Yeah. Good morning. Bill, just curious that when at some point that the COVID impact is going to be higher and if we see a more favorable environment, where are you going to spend money first? Is this in Bakken or in SCOOP? And also if we do see a $50 oil price, at that point is the activity level going to go back into your original budget activity level or that after COVID you’re going to have a lower growth rate on a lower activity level?

I’ll start with the last one, Paul, and that we highlighted earlier in this year that we were going to see a growth rate this year and an attenuation of the growth rate that we had over the five-year plan. So we’re expecting that this market share issue was going to be coming to fruition and it is the realization that we’re all beginning to see right now. We already had attenuated that. The slide that Jack was going to be showing the inventory and the strength of inventory, it’s not a function of inventory. This is a function of I just think we ought to do a little bit more measured pace. As for the Bakken versus the SCOOP, I think you’ll see there that we’re going to make that determination on the fly as to whether we’re seeing strengthening fundamentals on the gas or the fundamentals of the oil driving that. The good news is we’ve got full flexibility to do that. We’ve got a range of assets in the South that go everywhere from low GOR to high GOR. We’ve got assets up in the North that are really strong oil focus. With the portfolio that we have, we have that optionality.

And our next question will come from Gail Nicholson with Stephens. Please go ahead.

Good morning. Can you talk about your thoughts on the workover and recompletions in the current price environment, and has your philosophy on that program changed at all?

Level of workover activity.

Was it cost?

On the workover and recompletion? Is that your question?

Yeah. Just how you guys are thinking about that in the current price environment and if that philosophy on that program has changed at all going forward?

We currently don’t have a recompletion program active, and we had a few in the beginning of the year that in this environment we’ve discontinued that. From a workover perspective, we’ve kept the minimal amount of workover rigs active in the Bakken that we felt were necessary for the critical well activity that we have there, but have reduced that count pretty dramatically as well.

Some of our non-ops have done a fair amount of recompletions. They’ve still got a few in their system. We get quite a bit of data, and that’s something that we’ll be evaluating that data further as we go forward. So there’s still some progress there.

Most of that falls into what we describe as discretionary spending, and we’ve pretty much eliminated all discretionary spending.

Okay, great. Thank you.

This will conclude today’s question-and-answer session. I would like to turn the conference back over to Rory Sabino for any closing remarks.

Thank you very much for joining us today. Please address any further questions to the IR team, and have a great day.

Thank you.

The conference has now concluded. Thank you for attending today’s presentation, and you may now disconnect.