APA Corporation

Ladies and gentlemen, thank you for standing by and welcome to the Apache fourth quarter and full year 2020 financial and operational results conference call. At this time, all participants are in a listen only mode. After the speaker presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star zero. I would now like to hand the conference to your speaker today, Gary Clark, Vice President of Investor Relations. Please go ahead, sir.

Good morning, and thank you for joining us on Apache Corporation's fourth quarter and full year 2020 Financial and Operational Results Conference Call. We will begin the call with an overview by CEO and President John Chrisman, Steve Reine, Executive Vice President and CFO of will then provide further color on our results and 2021 outlook. Clay Breches, Executive Vice President of Operations, and Dave Fursell, Executive Vice President of Development, will also be available on the call to answer questions. Our prepared remarks will be just over 15 minutes in length, with the remainder of the hour allotted for Q&A. In conjunction with yesterday's press release, I hope you have had the opportunity to review our fourth quarter financial and operational supplement, which can be found on our investor relations website at investor.apachecorp.com. Please note that we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interests in Egypt and Egypt tax barrels. And finally, I'd like to remind everyone that today's discussions will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discussed today. A full disclaimer is located with the supplemental information on our website. And with that, I will turn the call over to John.

Good morning, and thank you for joining us. Today, I will recap Apache's 2020 accomplishments, discuss our fourth quarter results, and provide commentary on our outlook for 2021. First, I want to take a moment to acknowledge the severe weather and devastating power outages experienced here in Texas last week. Nearly all of our Texas-based employees were directly affected. Our field staff worked tirelessly to maintain safe operations, and like millions of Texans, our employees across the state experienced notable challenges, including a lack of power, heat, water, and many of the modern conveniences we all rely on. While it appears that numerous factors played into the situation, one thing is certain. This event has underscored the need for resilient and reliable energy infrastructure and supply. 2020 brought many unexpected challenges which required immediate and aggressive actions. Shortly after we issued our initial guidance for the year, a confluence of events signaled clear trouble for near-term oil prices. The Russians and Saudis, in a battle for market share, were flooding the market with supply. At the same time, The spread of COVID-19 was emerging as a significant threat to global demand. In response, on March 12th, we announced several important steps designed to protect cash flow in the event of a prolonged adverse oil price environment. We reduced our capital budget by 37% from the budget we had laid out just two weeks earlier. We cut our dividend by 90%. We initiated a shutdown of all drilling and completions activity in the U.S. and a reduction of rig activity in both Egypt and the North Sea, and with the significant reduction in planned capital activity, we decided to double our target for combined GNA and LOE cost savings from $150 million to over $300 million. While these actions seemed extreme to many, they turned out to be necessary and timely. Throughout 2020, relative to our original plan, we lost over $1.3 billion of oil and gas price-related revenue and more than $300 million of cash flow to working capital. Despite this, Apache finished the year with no increase in net debt when excluding Altus Midstream. We were even in a position to take advantage of volatility in the debt markets to buy back some bonds at a significant discount. and later issue $1.25 billion of new bonds to restructure the debt portfolio and protect near-term liquidity. In addition to these actions, our response to the pandemic was equally swift and effective. We protected employees and minimized operational disruptions by quickly implementing a work-from-home program for office staff and changes in field operating protocols. To date, there have been no known cases of a COVID-19 transmission from one Apache employee or contractor to another. I am also especially proud of the assistance we provided to the pandemic response in each of the communities where we operate. Finally, as we look back on 2020, one of the key highlights was our exploration program in Suriname, where we commenced activity under our joint venture with Total. We have now made four significant oil discoveries in our first four exploration tests and recently began the appraisal drilling program. Turning to the fourth quarter results, we ended 2020 on a strong note, beating our fourth quarter guidance for adjusted production, upstream capital expenditures, and LOE. Oil production in the quarter was slightly ahead of expectations, while gas and NGL production was notably strong, as we returned all previously curtailed alpine high volumes to production around the end of October. In the Permian Basin, we resumed completions activity in response to significantly lower service costs and improving oil prices. In Egypt, we continued to leverage our large acreage position and modern seismic program to further enhance our long-term exploration and development inventory. A recent example of this is the Tayam North discovery which encountered 88 feet of high-quality oil pay. We are waiting on pipeline connections to further assess the reservoir extent and potential for additional development locations. In the North Sea, we made an important oil discovery in the tertiary play with our lost GAN well, an offset to Ocker BP's Froskalar discovery on the Norwegian side of the border. In combination with two previously undeveloped Apache discoveries in the tertiary play, LawScan is part of a longer-term development opportunity that could contribute meaningful incremental volumes while leveraging existing infrastructure. Looking ahead to 2021, last night we announced an upstream capital program of $1.1 billion, consisting of approximately $900 million for development activities and $200 million for exploration, predominantly in Suriname. This program is expected to deliver substantial free cash flow under our assumed price deck of $45 WTI oil and $3 Henry Hub natural gas. In 2020, we directed a higher percentage of our development capital to international projects that generate better returns in a lower price environment. With the improvement in oil prices, we are returning to a very modest level of activity in the U.S. during 2021. In the Permian, we are currently running one rig and plan to add a second rig at mid-year. This measured approach will advance our objective of mitigating Permian oil production declines. We will likely need to add a third rig at some point to fully arrest the decline. At Alpine High, we have completed two lean gas ducts that are performing very well, and we are planning five similar completions this spring. While there are no specific alpine high drilling plans in 2021, we will continue to monitor commodity prices and remain flexible with this asset. Following several years without operating activity in East Texas, we recently added a rig in the Austin Chalk Plate. This rig will drill a few wells that are necessary to hold our core acreage position and preserve optionality. We believe the Austin Chalk, which is well situated near existing infrastructure, will likely merit future capital consideration. In Egypt, we plan to continue running five rigs this year. Our goal is to stabilize production and ultimately return Egypt to growth, both of which will require the addition of more rigs. We can quickly flex spending in Egypt, as conditions warrant, and we will monitor oil prices and cash flow for the appropriate time to do so. In the North Sea, the capital program remains relatively unchanged this year with one floating rig and one platform crew. While production from the North Sea is lumpy on a quarterly basis, we believe we can generally sustain output in the 55,000 to 60,000 BOE a day range for the next several years at this level of activity. Lastly, in Suriname, we began the transfer of Block 58 operatorship to Total at the beginning of the year. They are an excellent operator, and we look forward to this year's exploration and appraisal programs. On the exploration side, our fourth well, Keskesi, is continuing to explore deeper objectives in the Neocomian. As previously announced, we have selected the location for our fifth exploration well, Bonboni, which will be in the northern portion of the block. Total spud the first appraisal well in Block 58 earlier this month. which will be appraising aspects of both the Quas Quasi and Sapacara discoveries. I would like to close by discussing Apache's oil production trajectory and provide some perspective on maintenance capital levels. As previously noted, we chose to significantly reduce capital spending in 2020 and plan to maintain a conservative investment approach in 2021. One of the outcomes of this choice is that our global adjusted oil volumes decrease by 17% from the fourth quarter of 2019 to the fourth quarter of 2020. This year, we are projecting a much more moderate decline of around 1% to fourth quarter 2021. This implies the $900 million of capital investment we have earmarked for production and development activities is just a bit shy of the spend required to sustain global oil production at fourth quarter 2020 levels. As we look to 2022 and beyond, our goal is to establish a development capital investment budget that will, at a minimum, sustain production volumes for the long term. While we have experienced a very welcome oil and gas rebound over the last three months, our strategic approach remains centered around capital discipline and flexibility. As such, we are continuing to prioritize the retention of free cash flow to reduce debt, a focus on long-term returns over short-term growth, aggressive cost structure management, the advancement of our exploration and appraisal activities in Suriname, and continuous improvement in our ESG practices and metrics. In 2020, we increased the weighting of ESG goals in our short-term compensation calculation to 20% and refined our focus areas to air, water, communities, and people. During the year, we emphasized robust employee safety programs related to COVID-19, assisting our communities impacted by the pandemic, and advancing programs that foster a more inclusive workplace. We also made good progress on the environmental front with enhanced greenhouse gas data collection and expanded disclosures, particularly with regard to TCFD. We plan to continue to build on these efforts in 2021 with ESG goals that tie directly to compensation and include specific emissions and water usage targets and enhance our employees' experience. These include delivering less than 1% flaring intensity in the U.S., achieving fresh water consumption less than 20% of total water consumed, and further progressing our diversity and inclusion programs. And with that, I will turn the call over to Steve Reine, who will provide additional details on our two results in 2021 outlook.

Thank you, John. I'd like to provide a bit more color around Apache's fourth quarter results, debt management efforts in 2020, and our outlook for 2021. As noted in our news release issued yesterday, under generally accepted accounting principles, Apache reported a fourth quarter 2020 consolidated net income of $10 million. On a fully diluted basis, we incurred a loss of $16 million, or 4 cents per diluted common share. These results include items that are outside of core earnings. Excluding these items, the adjusted loss was $20 million, or 5 cents per share. Company-wide adjusted production for the quarter was 365,000 BOEs per day, a 7% decrease from the third quarter. This was driven by declines in the Permian Basin in Egypt, where we felt the impacts of reduced activity levels after the first quarter cut in capital spending. These declines were partially offset by increased North Sea production, primarily associated with the timing of workover activity. Lease operating expenses of $269 million for the quarter were below guidance, but did rise a bit from the third quarter. G&A expense of $76 million was at the low end of our guidance range. This was also an increase from the third quarter, but mostly due to mark-to-market accounting treatment of certain stock compensation programs. Entering 2020, one of our key financial goals for the year was to retain free cash flow to reduce debt. While the collapse in oil prices made this significantly more challenging, the decisive actions we took to reduce our capital program, cut operating and overhead costs, decrease our dividend, and numerous smaller actions enabled Apache to avoid further leveraging its balance sheet. We also took some important steps to rearrange the bond maturity profile and to create a cleaner runway for the next few years. Through a combination of discounted open market repurchases, tender offers, and call options, we reduced shorter-term bond maturities by $600 million, with only minor changes to our average maturity profile and coupon rate. We now have only $336 million of bonds maturing before November of 2025. We still intend to reduce debt levels through free cash flow retention, and if oil and gas prices sustain anywhere near current levels, we will make substantial progress in 2021. Further to the 2021 outlook, as John stated, we are planning an upstream capital budget of approximately $1.1 billion with the primary goals of advancing our exploration and appraisal activities in Suriname and stabilizing global oil production around fourth quarter 2020 levels. At this point, it looks like our planned capital program will fall just a bit short of stabilizing oil production. but we continue to look for ways to get more out of those investments. More specifically, to our production profile for 2021, we expect U.S. oil output to decline in the first quarter. This is primarily attributable to nine days of extensive Permian Basin shut-ins during the recent freeze event, as well as the timing of Permian duct completions during the quarter. Consequently, We expect a significant rebound in U.S. oil volumes during the second and third quarters, before backing off a bit in the fourth quarter to a rate similar to fourth quarter of 2020. Internationally, we anticipate continued declines for the year compared to fourth quarter 2020 levels as upstream capital investment remains below maintenance levels, and we will incur more downtime in the North Sea for scheduled maintenance turnarounds. In 2021, we are projecting LOE to rise approximately 7% year over year, which primarily reflects the impact of some cost deferrals from 2020. This includes items such as increased work overspending and platform maintenance in the North Sea. We also expect to see some higher foreign currency exchange impacts associated with the weakening U.S. dollar. G&A will also rise a bit this year to a run rate of around $75 million per quarter. In closing, we are cautiously optimistic for a year of improved oil and gas prices. Even if we fall a bit from the current strip, with a very conservative approach to capital budgeting, we should generate significant free cash flow for debt reduction. And with that, I will turn the call over to the operator for Q&A.

Thank you. As a reminder, to ask a question, you will need to press star 1 on your telephone. To withdraw your question, press the pound key. Please stand by while we compile the Q&A roster. Our first question comes from Doug Leggett with Bank of America. Your line is now open.

Thank you, guys. I appreciate all the color this morning. I got one set of questions on Suriname and one on workovers, if I may. So on Suriname, John, there's been a lot of incremental information, partly coming from your partners. including, as you pointed out in your release, the likelihood of an FID this year, first oil by 2025. And then you yourself talked about an appraisal program that appears to be capping both Quest Quasi and Sapicara. So I wonder if you could just walk us through what's going on in the appraisal and what the scale might be of a first development in your mind.

Well, Doug, thanks for the question. The first thing I'll say is I really don't want to add a lot of color to, you know, our partners' commentary along timeline. I mean, we're aligned with them. You know, what I would say is, is that, you know, given that when we made the press release after the Sapa Cara discovery, we said that it merited, you know, consideration for Fast Track, and it had those key ingredients. So it shouldn't come as a surprise that the very first appraisal well was is doing exactly that. We've always talked about the first four wells, and I'll go back and talk about Maka, Sapakara, Kwas Kwasi, and now Keskesi, is really four different kind of deep water turbidite channel systems. They are placed where potentially you could do some overlap and so forth, you know, as you start to think about development. So the nice thing about where that first well is placed, Sapakara West No. 2, is it will be appraising both aspects of Sapakara, and we get to see some of Kwas Kwasi. So, you know, it shouldn't come as a surprise. And, you know, we're obviously, you know, anxious to get the results. When we think about the appraisal program, it's just the next step following expiration. And in terms of scale, those are the things we want to determine, you know, through the appraisal program. So I don't want to get into discussions on that at this point. But, you know, we're going to be looking to determine things like flow rates, connectivity, you know, those types of things, boundaries, things we might see as you work through this. So, you know, we're anxious to get on with it and, quite frankly, excited with how quickly Totale has grabbed a hold and is running with it.

So I can't press you on scale, John?

You know, we'll take it one phase at a time, but we're in appraisal mode.

Okay. I'll let someone else ask about Keskegi, but I do want to ask about the maintenance capital, you know, just the trend that you've had there. I mean, it seems kind of remarkable to us that you're managing to hold at a climb as shallow as you are. presumably some of that capital is translating into workover costs in places like the North Sea. So I just wonder if you could kind of walk us through how you think about the dynamics of workovers versus capital. And really what I'm trying to drive to is, what do you think that sustaining break-even oil price is for that low decline that you seem to be able to hold in 2021?

You know, I mean, the thing I would say is, is, You know, I'm really proud of what our teams, our asset teams and our operations staff have been able to accomplish. I mean, in a really tough environment with COVID-19 and a lot more protocols added, I cannot say enough good things about our organization and all the hard work that's taken place. And you see that. You saw it in our cost structure reductions. You see it in these numbers. Not only did we reduce all the drilling rigs in the U.S., we dramatically cut the work over rigs in the U.S. and in the other areas as well. It just goes to show you with the focus and the effort we're putting on it. This year, we did pick up a rig in the Permian. It's one that made a lot of sense. to pick up. We plan to add another rig mid-year. And we're going to be just short, as I said in the commentary, we probably need to add another one, but we don't plan to do that right now to be able to kind of hold our oil production. We're just short of the activity levels in Egypt to kind of hold it. And North Sea is going to be lumpy, and we're kind of in that range now where we think we can manage it between, you know, 55 and 60. It's just going to be a lumpy profile with the turnarounds and the types of projects we're bringing on through subsea tiebacks in the barrel area. But I, you know, really, you know, kind of hats off to the operational staff and the asset teams because we're really managing things on cash flow. and managing the cost structure really hard, and it's amazing what that's done, you know, as a result to the oil curves.

I'll take the details offline, John, but I appreciate the answers. Thank you.

Thank you. Our next question comes from Bob Brackett with Bernstein Research. Your line is now open.

Good morning. Unsurprisingly, I'll follow up a bit on Suriname. If I think about the $200 million exploration budget, that seemed to have three buckets, a small amount going to Austin Chalk, some going to Suriname Exploration, and then the remainder going to appraisal in Suriname, where you're paying 12.5 cents on the dollar, effectively, because of the JV. Can you break those out any more for us, or should we just kind of think of it as one big lump?

Well, Bob, what I would say is, number one, the chalk money was not appraisal, right? It's development capital. We're You know, it's in an area where we've got leases that are expiring. When we had some wells, you know, we had to make a decision there to either drill those wells or let the acreage go. It's not exploration capital. So, you know, we feel good about we've been participating in offset wells. So the first thing I would say there. And then when we look at Suriname, you're right, there are two buckets. But it really will hinge on the types of wells that we're drilling. You know, the exploration wells will be 50-50. And at this phase of our joint venture, you know, the appraisal wells will be 12.5%. And so we really didn't break that bucket out. You know, clearly, you know, the first appraisal well, you know, we're paying 12.5% off, and clearly we're paying 50% of Keskesi. But that dollar amount doesn't change much from where it's been, you know, last year when we were running a rig at 50-50 the whole time.

Okay, interesting. A quick follow-up would be, what's the timeline for Stats Only deciding whether to back in for 20% and any thought on where their heads are?

Well, I mean, they actually have that election at the time you FID a project. So, you know, we've got some time there. Yeah, I think they would like to participate. That's what we've always planned on from the get-go. But we'd obviously, you know, be in a position to take additional interest if you get there. But that's, you know, they would come in on a point-forward basis at FID.

Okay, that's clear. I'll pause here and maybe hop in the queue later. Thanks. Thank you.

Thank you. And our next question comes from Janine Y. with Barclays. Your line is now open.

Hi, good morning, everyone. Thanks for taking our questions.

Good morning, Janine.

Good morning. Our first question is on the 2021 CAPEX budget, and you're anchored at the very conservative 45 and 3. And so what's your appetite for incremental activity if the strip ends up playing out? We know you said you'd be very conservative and you're going to watch things and be very measured. But you said that, you know, you ultimately need a third rig in the Permian to arrest declines. You have some really good opportunities in Egypt, and you maybe need a little more activity there to mitigate declines as well. So I guess where's your appetite on all of that, and where are you most likely to add that incremental activity if it could be done this year?

Yeah, Jean, right now our appetite is generating free cash flow that we can set aside for debt repayment. You know, we're just pointing out that to really stabilize Permian, you know, we do need to add another rig. There may be an opportunity in Egypt, but, you know, right now, I mean, like I said, we're going to be very disciplined on the capital. And, you know, we would just be very measured. And right now the appetite is to generate free cash flow for debt repayment.

Okay. We like free cash flow and debt repayment. That's good. And then my second question, maybe just following up on Bob's question just now, I might have missed part of it. In that $200 million in exploration capex, that's primarily Suriname, is there anything in there for offshore Dominican Republic? I think you all were, like, finalizing something on that a few months ago.

Yeah, there's a small bit there, Janine. I mean, we're starting to go through the work of scoping out our 3D seismic chute. So there is a little bit of money in there, but it's not a lot. But it would be captured.

Great. Thank you.

Thank you.

Thank you. And our next question comes from Bob Bracker with Bernstein Research. Your line is now open.

Well, I'd hop out of the queue, and I guess you put me back in. I was going to let other people get a chance.

Bob, I don't know what happened because there's a list here. So I would say the operator put you back in, but if you want to ask one since we've done it, I would say ask it.

I'll send her the check later.

We weren't trying to step over anybody else because there's a list here.

So I guess I'll stay on that Suriname theme, which is talking about getting to FID. Is there a drill stem test planned for the year? And I'm just kind of surprised by the speed at which you can go from no appraisal to FID in less than 12 months. Is there something you can do to give us comfort on that timeline?

You know, I would just say, you know, our partner is pretty confident in the ROC. And, you know, I mean, I'll just leave it at that. I mean, it's, you know, we've got four exploration wells now. We've been taking our time with those, collecting a lot of data. We've done sidewalk cores. We've done a lot of PBT analysis. You know, they're not well boards we intend to use, but we've been gathering a lot of data as we've gone along, and we've been doing a lot of lab work, you know, subsequent. So, you know, I'll just leave it at that. I mean, clearly we will be doing flow tests with the appraisal program is the other piece, Bob. But I'll leave it there. I don't want to, you know, I by no means want to do anything, but, you know, state we're going to the next phase. and I don't want to try to add any, you know, commentary to the timeline that our partners talked about, but, you know, we are moving on the appraisal wells that we think could be fast-tracked. Great. Thanks for that.

Thank you. And our next question comes from Harry Hallback with Raymond James. Your line is now open.

Good morning. You know, I was looking at Total's release and they said, you know, around nine wells are expected this year. Any sort of rough estimates on the timing of those and when we can expect results and kind of just the rough split for exploration and appraisal wells going forward?

I mean, all we'll really say, Harry, is there's two rigs. I would say, you know, that nine wells is their whole portfolio. But, you know, we've got two rig programs here that I would say. We drilled three plus wells with one rig line last year on the exploration front. Some of the appraisal wells could go quicker because you've now got penetrations in the basin, but some of these may take longer because of flow tests and things. So I would just say we haven't given that color. We've just said kind of think of it as an exploration rig line program and an appraisal program, and we're going to move on them concurrently.

Great. Thanks. Appreciate that. And then looking at the U.S., you know, what does a maintenance mode sort of program look like, including Alpine High? And, you know, how are the returns of Alpine High stacking up to the Austin Chalk or the other Permian stuff, just with the move in propane and butane prices lately?

Yeah, Harry, this is Dave Purcell. So when we think about maintenance in the Permian, we're thinking about it on the oil side. And so when we talk about three rigs, we're thinking about what it takes to keep oil production flat. We haven't run that math at Alpine. I think when you look at the forward curve on gas and NGLs, even though we have preliminarily positive results from the two ducts that are flowing back now, Given where oil prices are, it's unlikely in a limited capital budget that those compete within the Apache budget. But if they're economic, we're open to think about partnering with someone to help us move Alpine forward.

Great. Appreciate y'all taking my questions.

Thank you. Our next question comes from Michael Cialdo with Stiefel. Your line is now open.

Good morning, everybody. Thank you for taking my question. This is actually for Mike. I was wondering if you could provide additional color on the US. You mentioned you're adding a second rig, but just to confirm, to hit your guidance number, will you need that third rig, or your comments on adding that third rig are showing some upside potential to your guidance?

No, I mean, we do not have it planned. It's not in the plan, and obviously if it's not in the plan, it wouldn't be in our guidance. So we were just making the reference point that, you know, we're just shy on the oil side, and we would likely need, you know, one more rig in the Permian, which right now we do not plan to add. I want to be really clear there. Okay. And it's not in our guidance.

Okay. Thank you for that clarification. And going forward, you mentioned that maintenance mode. Is it fair to assume a slight growth in the U.S. to offset international volumes, or should it be maintenance all across the board?

Yeah, I think we're really, when we talk about this, we're talking about maintenance across the board.

Okay. Thank you. And last one for me, as for the Austin Chuck, a competitor of yours suggested a well-performance that could compete with a Permian. Do you have similar expectations for those wells?

Yeah, this is Dave again, Guillermo. We've been patient as we've watched this play develop. We have a big acreage position. It's legacy. We've participated in some non-op wells, and we have high expectations, which is why we're drilling these. But again, John said it. It allows us to preserve the optionality of this, again, to... bring in some additional capital if we choose to.

Thank you very much. That's it for me. Thank you.

Thank you. Our next question comes from Gail Nicholson with Stevens. Your line is now open. Good morning.

Steve, in your prepared remarks, you mentioned that there are some cost deferrals on the LOE side in 20 that are hitting in 21. Could you quantify that amount? And then what does a more normalized LOE rate look like post-21?

Yeah, I don't have a, sorry Gail, I don't have a quantification of the amount that was deferred from 2020, nor how much of that is actually showing up in 2021. I'd maybe just suggest that you could follow up with Gary after the call. Maybe we can get an estimate of that. But I think it's a, I don't think it's a material amount. but it's certainly contributing to the 7% rise in LOE from one year to the next. And sorry, what was the second part of the question?

Oh, I just wanted to know if we included that amount, what would a normal LOE run rate look like?

Yeah, obviously it would, the more normal, well, I think actually the 2021 amount is probably the more normal amount because what we've done is we've just deferred some stuff out of 2020 into 2021, we're not necessarily doubling up a lot of stuff. There could be a little bit in there. So you're probably in the low signal digits in terms of the band of error there in terms of doubling up some expense into 2021. I don't think it's got a material effect there.

Okay, great. And then in the supplement, you guys talked about the Egyptian decline rate is expected to moderate in 2021. Can you talk about where it is today and where you think it will be by year end and what is driving that moderation?

Yeah, this is Dave again. I think when you look at the, particularly in the Permian, you look at the way unconventionals behave, Yeah, oh, I'm sorry, in Egypt, I'm sorry, I misunderstood the question. Yeah, in Egypt, it's a combination of activity and where we're focused. You know, we have a pretty significant workover program there that is also really bringing in behind pipe. So, you know, as production declines, you tend to have an easier time holding it stable. So that's the real – the way the math works there in Egypt.

Okay, great. Thank you.

Thank you, Gail.

Thank you. Our next question comes from Scott Handled with RBC Capital Markets. Your line is now open.

Thanks. If I could move back to, you know, maybe discussing Alpine High. I mean, do you all think there's some latent value that's, you know, that's associated with the infrastructure or even, you know, maybe the gas, you know, the well and the gas production opportunity here? And if that's the case, is there opportunities for you guys to, you know, do something to get some of that value recognized, and specifically, too, on the infrastructure side with what you all have there as well as your joint venture agreements?

No, Scott, there's no doubt. I mean, you've got resource there. We've gone in and, you know, done a couple of ducts, which we said they were the first two we've done. They're performing very nicely. I think we've got five more ducts that we'll finish the duct program with later this spring. So there is opportunity there to potentially bring in some capital. I mean, what we've got right now with where our capital budget is, it's pretty tight, so we don't plan to add any. But there is opportunities to potentially look at some things out there.

Okay. Is that an initiative for you all, or is that just something that could happen?

Well, I mean, I'd just say that there's a lot of things we always work on that you don't spell out as things. You know, but, you know, I'll just leave it at that. It's, you know, it's something that we might be working on or would be thinking about, but there's, you know, nothing we've got set up or planned in the activity set.

No problem. Thanks for that. And then my next question is, you know, if you all could remind me in Egypt, you know, with the PSC and higher oil prices, like, At what point do you start getting to sort of that cap on the value? Are we a ways away from there? Obviously, I think the strip has moved up pretty nicely, and there is obviously some conversation out there whether we get into the next oil super cycle. I just kind of want to remind me the sensitivity to higher oil prices with that PSC.

No, I mean, the returns there are good. It's just things shift as you move higher, right? And you get to a point in there where, you know, inventory in the U.S. and Permian actually spins over and can be, you know, more attractive. So, you know, we're not in that ring. I mean, we're at a point today as if you go back and look, you know, last year we put out some priority sheets that kind of showed investment levels and with some price decks and kind of at 50 was where we considered Permian. You know, I mean, there's nothing that's changed off of that, those priorities that we put out there.

Understood. Thank you.

Thank you. Before we go to the next one, if I could just add a bit to that. I'd say that in the $50 to $60 Brent range, we've still got plenty of running room where price continues to add meaningful amount of value to the Egypt opportunities. So we're not We're not near any type of ceiling on value opportunities in Egypt. Nowhere near that.

Thank you. Our next question comes from Brian Singer with Goldman Sachs. Your line is now open.

Thank you. Good morning.

Hello, Brian.

I want to follow up on a couple of the topics. First, maybe starting with Suriname and the exploration appraisal budget that's largely the large component of $200 million. In a continued success scenario and reflective of the less demanding capital contracts as part of the joint venture, how do you see Suriname CapEx evolving in years to come, and how does the optionality of the call on Suriname Capital impact your willingness to flex other assets like Egypt, Alpine High, and Permian?

Yeah, Brian, I mean, the nice thing is you start shifting more dollars into appraisal and development, but the carry is really kicking in. So, you know, those numbers don't go up, so it doesn't hinder. I mean, that's part of why we structured that deal in the first place. It's really the expiration rigs that drive because of the 50-50. But, you know, obviously as you shift into development and, you know, assuming you'd FID something, then your dollars would go up. But, I mean, it's not going to be something we can't manage. It's not something that's going to take away capital from other areas.

Got it. Thanks. And then my follow-up is trying to piece together some of the comments from your opening remarks as well as other questions as it relates to the CapEx flexibility. You were very nimble in flexing CapEx to the downside in 2021. there seems to be a consideration to be nimble on the upside. And I was wondering if you could quantify if you were to stabilize production in the Permian with a third rig, stabilize production in Egypt, and if pricing in NGLs and natural gas warranted some greater activity in Alpine High, what the combined incremental capital would represent to make that happen.

Yeah, I mean, I'd say today, Brian, we're not – thinking about trying to be nimble there and add, right? I mean, we poured our plan. Actually, the rig we picked up in Permian, we've been paying standby rates on, so it made a lot of sense for us to pick that rig up. And when we reduced last year, we drastically reduced. In fact, like I said, we were paying some standby rates. So we're not really motivated right now to try to be nimble and pick up incremental capital. You know, we're just pointing out kind of where those things would be. But, I mean, right now, you know, I think Steve especially wants to see some dollars come in that we can earmark for debt repayment.

Great. Thank you.

Thank you. Our next question comes from Leo Mariani with KeyBank. Your line is now open.

You guys wanted to follow up here a bit on Suriname. Just wanted to dive a little bit into the neocomian, you know, zone here. You know, what can you kind of tell us about that particular zone? Is that present in the other, you know, three discoveries and then in general is it you know, present across your block or maybe just other areas, you know, of the basin? And has anyone else had any, you know, penetrations potentially elsewhere, you know, in the basin in this particular zone?

Yeah, great question. I mean, you know, when we talked about Block 58 in the first place, you know, we laid out more than a handful of different play types. And quite frankly, our first three play types are all upper Cretaceous. Campanian, Santonian are the first two. And then the third one actually is Toronian, which is also upper Cretaceous. We attempted to get down to the Toronian, you know, with Maca, but we were unable to due to pressure. You know, with the Neocomian, it is actually a lower Cretaceous target. You know, when I talk about the upper Cretaceous, Campanian, and Santonian, they're really deep water areas. channel and levy turbinates. But the Neocomian is lower Cretaceous and it's more shallow water carbonate reef buildups. And so I will tell you that we're not through the first two targets. We've got two Neocomian targets to test in Kaskassee. What we had to do was swap out the BOPs And so we're in the process of doing that. We'll be back to drilling. But these are carbonate reefs. They're pretty visible on the seismic. But this will be the first test for us. And this was an optimal place to go on down through the source rock to the Neocomian. And we're anxious to see. But it is exploration. They're visible. If it were to work and bear the right fluids, then it sets up a whole string of these that are down there. So it's a play concept test, and this just was the logical best place to do the first test for the neocomium.

So just to confirm, you guys certainly believe this is present across your block and potentially in other areas in Suriname, and is this kind of the first test that you're aware of?

Well, I mean, I'd say, you know, when we've got multiple, it doesn't mean across the block. I mean, what you've got to understand is with the geology here, you know, there are play types that are present in, you know, as you start thinking about other play types, there are play types in this portion of the block that are present in some areas but not everywhere. So it gets back down to what the settings were like when it was laid down. And I said this is lower Cretaceous. It's more, you know, shallow water, carbonate reef buildups. And so there's probably a trend of those, you know, that there is a trend that moves across our block. But, you know, we're focused mainly on our block. And, you know, this is the first one. I'll just say that it's exploration. So, obviously, you know, the chance of success you put in there that it's, you know, it's likely not going to work. But, you know, if it does work, it does set up some more targets for us. But we are – it is an exploration well for a reason. Right. It's a play concept, but if it happens to work, we've got, you know, more of these on the block that would be additive and, you know, potentially could become part of whatever you did, you know, in terms of an FID somewhere down the road.

That's a very helpful color for sure. I just wanted to shift over to Egypt here. You guys obviously made a discovery at Tyne North. Sounds like you're waiting on, you know, pipe there. Just wanted to get, you know, a sense of when – You guys might think you'd be able to get back out there just to, you know, high-level time frame. Is it something that we can just talk about just in a matter of months where you can go out there and get a better look at the appraisal? Or is this something that could be, you know, longer term that might get pushed into next year?

No, it would be pretty quick. You know, the nice thing about Western Desert is we've got good infrastructure. I think the most important thing with TIAM is it proves concept with the new seismic because it's something that we would not have seen without the new seismic. And while it's a very nice discovery, we need to do some flow testing and things to figure out if there's offsets and how many. Most importantly, it's proof of concept. And we've got some other key wells that are on the rig schedule that are coming pretty soon. So it's just further validation of the time we've invested over the last few years with sewing together more acreage shooting the seismic and really refining some of our interpretation skills on what we're doing there. So it's just a lens into the rock that you wouldn't have seen otherwise, and that's what we're excited about.

Okay, good color. Thanks.

Thank you. As a reminder, to ask a question, you will need to press star 1 on your telephone. Our next question comes from Neil Dingman with Truist Securities. Your line is now open.

Morning, John and team, and thanks for squeezing me in maybe before Bob's third one. So a quick question for you. Looking at slide 12 just on the operating cash margins, John, I mean, obviously you continue to have great margins on North Sea among the others. I'm just wondering, given the type of margins you continue to see there, why not push that even further?

Well, I mean, I think the key there is we're in a pretty good rhythm. If you look at what we did last year, we had two platform crews, They're actually, you know, one at barrel and one at 40s, and we started alternating those. You know, we're in a pretty good cadence of projects. With the one rig, we've been doing what we could do in terms of prioritizing. We've got a really nice discovery there with LOSCAN. So, you know, I think we're in a good place with where we are, a really good cadence. And, you know, when you look at our other projects, types of opportunities across the portfolio, while the margins are really good there, you know, it's, I think we're, you know, we're investing and we're showing, you know, good work. And now we've got a tertiary project that we're, you know, that we're working on, not ready to talk about yet. But I think we're in a good cadence in the North Sea. Okay.

And then just lastly, can you talk just on Egypt about being still, is it pre-cash flow independent, I assume, John, and will continue to be?

Yes. No, I mean, we've got a good, solid business there. You know, we've built it over 25 years now. You know, we reduced activity when we had to everywhere. I think there's the opportunity, as Steve mentioned, we've got a lot of opportunity in Egypt. I think the new seismic and the new acreage is going to open some things up. And there's more to do there. But, you know, we're always working on preserving cash flow and those cash margins. everywhere, and that's something we've been working on across the entire portfolio.

Perfect. Thank you.

You bet.

Thank you. Our next question comes from David Heikkinen with Heikkinen Energy. Your line is now open.

Good morning, and first and foremost, I hope all you and yours fared well through the freeze and thaw. It sounds like you did, so that sounds good. Well, thank you, Dave. And then Also, just a couple quick hits, kind of good luck with the neochromium chromium. It sounds like I could characterize it as a string of pearls type prospect or trend, but you hit this one and then you'll have other high spots that are just going to follow along the same depth position.

Yeah, I mean, I would say that's, you know, how you could think about it, right? I mean, they're definitely – that's how carbonate reefs work in a shelf – shallow water environment.

That's what you're seeing, though. So you're seeing that type of string of pearls is what I was getting at.

Yeah, there's multiple targets that this would set up. But it's deep, you know, and, you know, there's risk, right? But we'll see what happens.

And then just, Dave, you kind of hit on some of the base decline tempering, and you had it in the slides. I don't think I heard an answer as far as at this, you know, you got the sustainably low level of CapEx and you have a basic oil decline tempering in 2021. Can you put any numbers to that tempering as you roll into 2022? Your sustaining CapEx sounds like it might go down and your operating expenses don't sound like they would go up. So I'm trying to think of how things temper through the year.

Yeah, I think if, let's talk about the Permian for a minute. We've given some numbers on base decline in the past. I don't have those at the tip of my fingers, but you know how unconventionals work. As you anniversary in the big first year production decline, you start to moderate the declines on the unconventional, and then we have obviously a big legacy position. So think about a third or more of our Permian production is a very shallow decline that the central basin platform type wells. So, you know, we have an advantaged position. We never got into that supersized growth mode in the Permian. So the first year declines that we anniversaryed in weren't as big as others. So when we look at the capital required for sustaining production, it's kind of in that three-rig mode or three-rig level. And you'll see the kind of similar analysis if we look at Egypt as well. It's a bit more conventional declines, but you'll see as overall production declines moderate, it becomes easier to hold production at those levels. So I don't have numbers in front of me, but that's directionally where the why the maintenance capital is probably lower today than, than what we've talked about in the past.

And then just an absolute debt level target. Do you have one for this year post the use of cash?

Not necessarily a specific debt level target, but you know, my target is as low as possible. So, you know, longer term we're, You know, we're trying to get – we've said this before. We're trying to get back to, you know, something below two, approaching one and a half times debt to EBITDA. You know, we were getting close in 19, and then 2020 happened. You know, it looks like this year, you know, at $55 WTI, we're going to be approaching two again. At the current strip, we'd actually be below two. So, and that's with the current level of debt. And, you know, we should be able to generate a significant amount of free cash flow at anything $55 or above. There's going to be a huge amount of free cash flow. We're planning on being free cash flow positive, you know, for a few hundred million at $45. So, any... Absent a 2020-ish collapse in oil price, we're going to generate quite a bit of free cash flow this year. So I think we're going to get debt to EBITDA back in the right direction by the end of this year and should be quite a bit stronger by the time we enter 2022. Thank you, guys.

That's very helpful.

Thank you. I am not showing any further questions at this time. I would now like to turn the call back over to CEO John Crickman for closing remarks.

Yes, thank you. I really want to close by the following key points. Despite the recent run in oil prices, our priorities have not changed. We remain focused on funding projects that provide the best returns over the longer term, maintaining a balanced portfolio, generating free cash flow to pay down debt, and continuing to move our CERN program forward. We're taking a very measured approach with our 2021 capital program, and you've seen that through the Q&A today. We ended 2020 with zero rigs in the Permian, and the combination of higher WTI prices and lower service costs make this an appropriate time to restart a very modest drilling program. Our goal is not to pursue growth, but to sustain oil production beyond 2021. Our program in Suriname is progressing well. The transition to Total as operator has gone smoothly, and we are aligned with our partner on both the appraisal and expiration programs. And most importantly, the objective of achieving first oil as quickly and as safely as possible. We look forward to updating you on our continued progress throughout the year. Thank you.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.