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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. [Operator Instructions] Please be advised that today's conference is being recorded.
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 Christmann. Steve Riney, Executive Vice President and CFO, will then provide further color on our results in 2021 outlook. Clay Bretches, Executive Vice President of Operations and Dave Pursell 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've 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 interest 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 discuss 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 Apaches 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 Saudi's 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 12, 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 2 weeks earlier. We cut our dividend by 90%. We initiated a shutdown of all drilling and completions activity in the US and a reduction of rig activity in both Egypt and the North Sea, and with the significant reduction and planned capital activity, we decided to double our target for combined G&A and LOE cost savings from $150 million to over $300 million. While these actions seemed extreme to me, it 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 in lender 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 the 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'm 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 continue 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 Tiam 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 Loscan well, an offset to Aker BP's discovery on the Norwegian side of the border.
In combination with two previously undeveloped Apache discoveries in the tertiary, Loscan is part of a longer-term development opportunity that could contribute meaningful incremental volumes while leveraging existing infrastructure. Looking ahead in 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 to 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 US 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. They 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 play. This rig will drill a few wells that are necessary to hold our core acreage position and preserve optionality. We believe that 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 Kwaskwasi and Sapakara 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 our global adjusted oil volumes decreased 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 in fourth quarter 2020 levels. As we look to 2022 and beyond, our goal is to establish a development capital investment budget that will add a minimum sustained 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 includes specific emissions and water usage targets and enhance our employees' experience. These include delivering less than 1% flaring intensity in the US, 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 Riney, who will provide additional details on our Q 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 $0.04 per diluted common share. These results include items that are outside of core earnings. Excluding these items, the adjusted loss was $20 million or $0.05 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 and 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 work-over activity. These 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, decreased 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 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 US Oil output to decline in the first quarter. This is primarily attributable to 9 days of extensive Permian Basin shut-ins during the recent freeze event as well as the timing of Permian DUC completions during the quarter. Consequently, we expect a significant rebound in US 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-over spending and platform maintenance in the North Sea.
We also expect to see some higher foreign currency exchange impacts associated with the weakening US 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.
[Operator Instructions] Our first question comes from Doug Leggate with Bank of America. Your line is now open.
Thank you, guys. Appreciate all the color this morning. I got one set of questions on Suriname and one on work-overs, if I may. So on Suriname. John, there's been a little bit of incremental information, partly coming from your partner, including as you pointed out in your release, the likelihood of an FID this year, [indiscernible] by 2025 and then you yourselves spoke about am appraisal program that appears to be topping both KwasKwasi and Sapakara. So, I wonder if you could just walk us through what's going on in the appraisal and what the scale might be of our first development in your mind.
Doug, thanks for the question. The first thing I'll say is, I really don't want to add a lot of color to our partners' commentary, a long timeline. I mean we're aligned with them. What I would say is given that when we made the press release after the Sapakara discovery, we said that it merited consideration for fast track and had those key ingredients. So it shouldn't come as a surprise that the very first appraisal well is doing exactly that. We've always talked about the first four wells and I'll go back and talk about Maka, Sapakara, KwasKwasi, and now Keskesi. It is really four different deep-water turbidite channels systems. They are placed where potentially you could do some overlap and so forth as you start to think about development. So the nice thing about where that first well is placed, Sapakara West. Number 2, is it will be appraising both aspects of Sapakara and we get to see some KwasKwasi? So, it shouldn't come as a surprise and we're obviously anxious to get the results. When we think about the appraisal program, it's just the next step following exploration. In terms of scale, those are the things we wanted to term through the appraisal program.
So I don't want to get into discussions on that at this point, but we're going to be looking to determine things like flow rates, connectivity, those types of things, boundaries, things we might see as you work through this. So we're anxious to get on with it and quite frankly excited with how quickly Total has grabbed the hold and is running with it.
So, I can't press you on scale, John?
You know, we will take it one phase at a time, but we're in appraisal mode.
Okay. I'll let someone else talk about Keskesi but I think when I ask about the maintenance capital, just the trend that you find, it seems kind of remarkable to us that you're managing to hold the decline as shallow that you are, presumably some of that capital is translating into work-over 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 work-overs versus capital. I'm really what I'm trying to drive to is what do you think that sustaining breakeven oil prices for that decline that you seem to be able to hold in 2021.
Yes, I mean the thing I would say is, I'm really proud of what our asset teams and our operation 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 has taken place and you see that, you saw in our cost structure reductions, you see it in these numbers. Not only did we reduce all the drilling rigs in the US, we dramatically cut the work-over rigs in the US and then the other areas as well. And it just goes to show you what the focus and the effort we're putting on it. This year, we did pick up a rig in the Permian. It's the 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 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 tie-backs in the Beryl area. But, really, kind of hats off to the operational staff on 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 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 seems 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. It's an area where we've got leases that are expiring. We had some wells, we had to make a decision there to either drill those wells or let the acreage go. It's not exploration capital. So, we feel good about we've been participating an offset well, so the first thing I would say there. 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. The exploration wells will be 50/50. And at this phase of our joint venture, the appraisal wells will be 12.5% and so we really didn't break that bucket out. Clearly, the first appraisal well, we're paying 12.5%, and clearly, we're paying 50% of Keskesi. But that dollar amount doesn't change much for where it has been 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 Staatsolie deciding whether to back in for 20% and any thought on where their heads are?
I mean, they actually have that election at the time you FID a project. So we've got some time there. I think they would like to participate. That is what we've always planned on from the get go. But we would obviously be in a position to take additional interest if you get there. But 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. And our next question comes from Jeanine Wai at Barclays. Your line is now open.
Hi, good morning, everyone. Thanks for taking our questions.
Good morning, Jeanine.
Good morning. Our first question is on the 2021 CapEx budget and your 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 would be very conservative and you're going to watch things and be very measured. But you said that you ultimately need a third rig in the Permian to arrest decline, you have some really good opportunities in Egypt and you maybe need a little more activity there to mitigate decline as well. So I guess what is your appetite on all of that and where are you most likely to add that incremental activity if it could be done this year?
Yes, Jeanine. Right now, our appetite is generating free cash flow that we can set aside for debt repayment. And we're just pointing out that to really stabilize Permian, we do need to add another rig. There may be an opportunity in Egypt, but right now, like I said, we're going to be very disciplined on the capital and 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 are finalizing something on that a few months ago.
Yes, there is a small bit there, Jeanine. I mean where we're starting to go through the work and scoping out our 3D seismic shoot. So there is a little bit of money in there, but it is not a lot that it would be captured.
Great, thank you.
Thank you.
Thank you. Our next question comes from Bob Brackett with Bernstein Research. Your line is now open.
Well, I had hopped 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 is a list here. So I would say the operator puts you back in. But if you want to ask one since we've done it. I would say, I ask it. But we weren't trying to step over anybody else. But there is 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?
Yes, I would just say, our partner is pretty confident in the rock, I mean I'll just leave it at that. I mean we've got four exploration wells now, we've been taking our time with those, collecting a lot of data, we've gone sidewall cores, we've done a lot of PBT analysis. They're not well more than 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 subsequent. So, I'll just leave it at that. I mean clearly, we will be doing flow tests with the appraisal program as the other piece, Bob. But I'll leave it there. I don't want to by no means want to do anything but state we're going to the next phase. And I don't want to try to add any commentary to the timeline that our partners talked about. But 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 Halbach with Raymond James. Your line is now open.
Good morning. I was looking at Total's release and they said around nine wells are expected this year. Can you sort of rough estimates on the timing of those and when we can expect results and kind of just be - for exploration and appraisal wells going forward?
I mean, all we really say here is, there's two rigs. I would say that nine wells is their whole portfolio. But 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 might take longer because of flow test 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 US, what does that maintenance mode, sort of, program looks like including Alpine High, and how is the returns to Alpine High stacking up to the Austin Chalk or the other Permian steps just with the moving propane and butane prices lately.
Yes, Harry, this is Dave Pursell. 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. And we're going to run that map 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 DUCs that are flowing back now, given where the oil prices are, it's unlikely in a limited capital budget that those compete within the Apache budget, but if there're economic, we're open to think about partnering with someone to help us move Alpine forward.
Thanks. Appreciate you all taking my questions.
Thank you. Our next question comes from Michael Scialla with Stifel. Your line is now open.
Good morning, everybody. Thank you for taking my call.
Good morning, Mike,
This is actually Guillermo stepping in for Mike. I was wondering if you could provide additional color on the US. You mentioned you 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 is not in the plan, it wouldn't be in our guidance. So we were just making the reference point that we're just shy on the oil side and we would likely need one more rig in the Permian, which right now we do not plan to add, I want to be really clear there. It is not in our guidance.
Okay, thank you for the clarification. And going forward, you mentioned maintenance mode, is it fair to assume a slight growth in the US to upset international volumes or should it be maintenance all across the board?
Yes, I think when we talk about this, we're talking about maintenance across the board.
Okay, thank you. And the last one for me. I suppose Austin Chuck, a competitor of yours, suggested a well performance that could compete with the Permian. You have similar expectations for those wells?
Yes, this is Dave again, Guillermo. We've been patient as we've watched this play develop. We have a big acreage positions legacy, we participate 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 and have a great day.
Thank you.
Thank you. Our next question comes from Gail Nicholson with Stephens. Your line is now open.
Good morning. Steve, in your prepared remarks, you mentioned that there is some cost deferrals on the LOE side in '20 that are hitting in '21. Could you quantify that amount and then what is the more normalized LOE rate look like post '21?
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; maybe just suggest that you can follow up with Gary after the call, maybe we can get an estimate of that. But I don't think it is a material amount. But it's certainly contributing to the 7% rise in LOE from one year to the next. Sorry, what was the second part of the question?
I just wanted to know if we [indiscernible] amount, what would the normal LOE run rate look like?
Yes. 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 single 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.
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?
This is Dave again. I think when you look at, particularly in the Permian, you look at the way unconventionals behave. I'm sorry I misunderstood the question. Yes, in Egypt, it's a combination of activity and where we're focused. We have a pretty significant work-over program there that is also really bringing in behind pipe resource. So as production declines, you tend to have an easier time holding it stable. So that's the way the math works there in Egypt.
All right. Thank you.
Thank you, Gail.
Thank you. Our next question comes from Scott Hanold with RBC Capital Markets. Your line is now open.
Thanks. If I could move back to maybe discussing Alpine High, I mean do you all think there some latent value that's associated with the infrastructure or even maybe the gas, the well in the gas production opportunity here is, and if that's the case, is there opportunities for you guys to 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 is no doubt. I mean you've got resource there, we've gone in and done a couple of DUCs, which we said there are the first two we've done. They're performing very nicely. I think we've got five more DUCs. It will finish the DUC 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 free all or is that just something that could happen?
I mean, I'd just say that there is a lot of things we always work on that you don't spell out. But I'll just leave it at that. It's something that we might be working on or would be thinking about, but there's nothing we've got set up or planned in the activity set.
No problems. Thanks for that. And then, my next question is, if you all could you remind me in Egypt with the PSC and higher oil prices, at what point do you start getting to sort of cap on the value [indiscernible] 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 that things shift as you move higher, right. And you get to a point in there where inventory in the US and the Permian actually spends over and be more attractive. So we're not in that range. I mean we're at a point today, if you go back and look last year, we put out some priority sheets that kind of showed investment levels with some price decks and kind of at 50 was where we considered Permian. I mean there's nothing that's changed off that to those priorities that we put out there.
Understood. Thank you.
Thank you.
Sorry, before we go to the next, 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 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 and good morning.
Morning, Brian.
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 do the optionality of the call on Suriname capital impact your willingness to flex other assets like Egypt, Alpine High, and Permian?
Yes, Brian, I mean the nice thing is as you start shifting more dollars into appraisal and development with the carriers really kicking in. So 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 exploration rigs that drive because of the 50-50. Obviously as you shift into development and assume a new FID something, then your dollars will go up but I mean it's not going to be something we can 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 2020. 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 pricing in NGLs and natural gas warranted some greater activity in Alpine High, what the combined incremental capital would represent to make that happen?
Yes. I mean, I'd say today, Brian, we're not thinking about trying to be nimble there and I add, right, I mean we pulled 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 rate. So we're not really motivated right now to try to be nimble and pick up incremental capital, we're just pointing out kind of where those things would be. But, I mean, right now, 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 KeyBanc. Your line is now open.
I just wanted to follow up here a bit on Suriname. Just wanted to dive a little bit into the Neocomian zone here. What can you kind of tell us about that particular zone? Is that pricing and the other 3 discoveries, and then in general, is it present or maybe just other areas of the basin and has anyone else had any penetrations potentially elsewhere in the basin in this particular zone?
Yes, great question. I mean, you know, when we talk about Block 58 in the first place, 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 is actually [indiscernible] which is also upper Cretaceous. We attempted to get down to the Maka [ph], but we were unable to do to pressure. 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 channel and turbidite [ph]. But the Neocomian is lower Cretaceous and it's more shallow-water carbonate reef buildups and so in others. I will tell you that we're not through the first two targets. We've got to Neocomian targets to test in Keskesi. What we have to do is 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 Neocomian.
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 in the basin?
No. I mean, I'd say when we've got multiple domains across the block. I mean, what you've got to understand is with the geology here, there are play types that are present in as you start thinking about other play types in those portion of the block that are present in some areas but not everywhere. So it gets back down to what the settings where like when it was laid down and I said this was lower Cretaceous, it's more shallow water carbonate reef buildups. And so there's probably a trend of those. There is a trend that moves across our block. But we're focused mainly on our block. And this is the first one, obviously it is exploration. So obviously the chance of success you put in there is likely not going to work. But if it does work, it does set up some more targets for us. But it is an exploration well for a reason. It is a play concept, but if it happens to work, we've got more of these on the block that would be additive and potentially could become part of whatever you did in terms of an FID somewhere down the road.
Thanks, very helpful color for sure. So I'm going to shift over to Egypt here. You guys obviously made a discovery at [indiscernible] sounds like you're waiting on pipe there. Just wanted to get a sense of when you guys might think you'd be able to get back out there, just high-level timeframe. Is it something that we could talk about just in a matter of months, we can go out there and get a better look at the appraisal, or is this something that could be a longer term that might get pushed into the next year?
No, we're pretty quick. The nice thing about Western Desert is we've got good infrastructure. I think the most important thing with [ph] is it proves concept with the new seismic because it's something that we would not have seen with seismic [ph], and while it's a very nice discovery, we need to do some flow testing and things to figure out if there is 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 selling 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, which you would have seen otherwise, and that's what we're excited about.
Okay. Good color. Thanks.
Thank you. [Operator Instructions] Our next question comes from Neal Dingmann with Truist Securities. Your line is now open.
Good morning, John and team and thanks for squeezing me in and maybe before Bob's third one. So a quick question for you, look at slide 12 just on the operating cash margins. John, you obviously 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 pretty good rhythm, if you look at what we did last year, we had two platform crews, they're actually one at Beryl and one at Forties, we started alternating those. 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 [indiscernible]. Yes, I think we're in a good place with where we are. A really good cadence. And when you look at our other types of opportunities across the portfolio while the margins are really good there, I think we're investing and we're showing good work and now we've got a tertiary project that we're going to work on, not ready to talk about yet. But I think we're in a good cadence in the North Sea.
Okay. And then just the last. Can you talk just on Egypt with that being, still is it free cash flow independent I assume, John, and we will continue to be.
No, I mean we've got a good solid business there. 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 is more to do there. But 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 - yours fared well through the freeze and thaw; it sounds like you did so, that sounds good.
Thank you, Dave.
Also just a couple of quick hits, kind of good luck with the Neocomian. It sounds like, I could characterize it as a string of pearls-type prospect or trend that you hit this one and then you'll have other high spots that are just going to follow along the same depth position.
Yes, I mean I would say it's how you could think about it, right. I mean, definitely it's all carbonate reefs working a shallow water environment.
That's what you're seeing. So you're seeing that type of string of pearls is what I was getting at.
Yes, there are multiple targets that this would set up, but it's deep, and 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 you got the sustainably low level of CapEx and you have a base [ph] declined 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 some? So I'm trying to think of how things temper through the year.
Yes. 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 an obviously big legacy position. So think about third or more of our Permian production is a very shallow decline that was Central Basin Platform-type well. So we have an advantaged position. We never got into that super-size growth mode in the Permian. So the first-year declines that we anniversaried in weren't as big as others. So when we look at the capital required for sustaining production, it's kind of in that 3 rig level and you'll see the 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 don't have numbers in front of me, but that's directionally why the maintenance capital is probably lower today 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. My target is as low as possible. So longer term, we've said this before, we're trying to get back to something below 2, approaching 1.5 times debt to EBITDA. We were getting close in 2019 and then 2020 happened. It looks like this year at $55 WTI, we're going to be approaching 2 again. At the current strip, we'd actually be below 2. And that's what the current level of debt. And 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 for a few 100 million at $45. So 2020-ish [ph] 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 to be quite a bit stronger by the time we enter 2022.
Thank you, guys. That's very helpful.
Thank you. I'm not showing any further questions at this time, I would now like to turn the call back over to CEO, John Christmann for closing remarks.
Yes, thank you. I really want to close 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 program forward. We are 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 exploration 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.