APA Corporation (APA) Q1 2020 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, thank you for standing by, and welcome to the Apache Corporation’s First Quarter 2020 Earnings Announcement Webcast. At this time, all participants’ lines are in a listen-only mode. [Operator Instructions] I would now like to hand the conference over to your speaker today, Mr. Gary Clark, Vice President of Investor Relations. Sir, you may begin.

Good morning and thank you for joining us on Apache Corporation’s First Quarter 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 summarize our first quarter financial performance; Clay Bretches, Executive Vice President of Operations; and Dave Pursell, Executive Vice President of Development, Planning, Reserves and Fundamentals will also be available on the call to answer questions. Our prepared remarks will be approximately 15 minutes in lengths 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 first 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. 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. As we review our first quarter results today, many Apache employees around the world are continuing to work remotely as part of our COVID-19 response. I would like to wish all of them and those of you, who are doing the same good health as we worked through a very trying time. I also want to acknowledge and thank the Apache team for their dedication and hard work in the face of a very challenging economic and operational environment. They are successfully and safely delivering day-to-day business activities in the face of a sudden and unprecedented change to life as we knew it. My heartfelt appreciation goes out to every one of our great Apache employees and contractors as well as our partners and stakeholders. The global economy and the energy industry have been deeply impacted by COVID-19. as we navigate this crisis, Apache’s primary priorities are keeping the health and safety of our employees and the communities, in which we operate paramount in our decision-making and preserving the inherent value and optionality of our diverse asset base for the long-term. Thus far, our efforts have been successful, and we’re very fortunate to have seen only a few isolated COVID-19 cases throughout the organization. We acted quickly to close offices and implement work from home processes as well as stringent operational protocols in the field. We also have in place contingency plans to ensure continuity in the event Apache incurs a more widespread or sustained impact. In the rest of my prepared remarks, I will discuss the primary actions we are taking to preserve the value of our assets and protect our balance sheet. Summarize our long-term objectives, which have not changed, and lastly, comment on our outlook for the remainder of 2020. While the current crisis is much more severe and complex, some key lessons learned from the 2014 oil price collapse are informing the decisions we are making today. In late February, we communicated our initial 2020 budget at an assumed WTI oil price of $50 per barrel. This seemed appropriate given prevailing supply and demand fundamentals and strip pricing at the time. In early March, OPEC+ failed to reach consensus on supply cuts and it became apparent that COVID-19 would cause an unprecedented amount of demand destruction. Apache responded to the old price drop associated with these events quickly and decisively. On March 12, we announced a plan to reduce activity in Egypt and the North Sea and to eliminate all U.S. drilling and completion activity. This resulted in a $650 million decrease in our 2020 upstream capital budget, which is now down nearly 55% from 2019. We also announced a 90% reduction to our dividend that’s preserving $340 million of cash flow on an annualized basis and strengthening our liquidity. To protect cash flow from further downside price dislocation, we entered into substantial oil hedge positions primarily for the second and third quarters, which we believe have the most volatility risk. We implemented deeper cost cutting measures announcing on April 1, an increase in our estimated annualized cost savings to $300 million, up from $150 million a month earlier. Apache benefited from the significant progress already made on our organizational redesign, which commenced in the third quarter of 2019. This enabled us to make the incremental cost reduction decisions confidently without compromising safety, asset integrity or our ability to resume activity when warranted. Finally, we have conducted a thorough price sensitivity analysis and operational evaluation of oil producing wells across the company, which is now informing the methodical and integrated approach we are taking to rolling production shut-ins and curtailments. This process will enable us to preserve cash flow in this distressed and vulnerable price environment and protect our assets. All of these actions were carefully planned and none were taken lightly. While very difficult, they were necessary to preserve liquidity and ensure ample runway to return to a more sustainable and profitable price environment. Next, I would like to reiterate our longer-term objectives, which still hold true despite some of the short-term impacts of the current situation. First, Apache will budget conservatively, aggressively manage our cost structure to ensure free cash flow generation and prioritize debt reduction to strengthen our balance sheet. We will maintain a balanced and diversified portfolio, and continue to invest for long-term returns rather than production growth. In the Permian, we will continue building economic inventory and maintain optionality, and in Egypt and the North Sea, we will flex activity to preserve free cash flow generation. Lastly, we will continue to enhance our portfolio through exploration. Our recent success, offshore Suriname is a prime example of this strategy and Block 58 remains a clear priority for Apache. As we look to the remainder of 2020, there are a number of fundamental uncertainties. The most important of these is the timing and magnitude of a recovery in demand for oil is supply response alone cannot solve this problem in the short-term. For Apache, the best course of action is to aggressively reduce our cost structure, protect our balance sheet, and manage operations to preserve cash flow. Our diversified global portfolio gives us the ability to optimize capital allocations as market conditions change. Just as we did following the oil price crash in 2014, we have left intact a higher proportion of international capital investment, which offers better returns than the U.S. in a lower price environment. To wrap up, Apache is taking the necessary steps to manage cash flow and protect our balance sheet. We have ample liquidity and a long runway to carry us through to a better price environment, and will maintain the flexibility and capacity to increase activity in a thoughtful manner as conditions warrant. And with that, I will turn the call over to Steve Riney, who will provide additional details on our first quarter in 2020 outlook.

Thank you, John. My remarks this morning will provide a few more details on first quarter 2020 results and our outlook for the remainder of the year. I will also comment on the strength of Apache’s liquidity position, which is more than sufficient to bridge this significant and potentially prolonged downturn. As noted in our news release issued yesterday, under Generally Accepted Accounting Principles, Apache reported a first quarter 2020 consolidated net loss of $4.5 billion or $11.86 per diluted common share. These results include items that are outside of core earnings, the most significant of which are non-cash impairments totaling $4.5 billion. Impairments were driven primarily by the impact of weak oil prices on the carrying value of our proved properties. Most of these impairments were in legacy vertical developments in the Permian basin, excluding these and other smaller items adjusted earnings for the quarter were a loss of $51 million or $0.13 per share. G&A expense in the quarter was $68 million, which was considerably below our guidance of $120 million. Some of our stock award programs are cash settled and each quarter accounting rules require us to mark-to-market the accrued liability for these awards based on changes in our share price. Typically, this has not been material, but it resulted in more than a $30 million reduction in G&A expense for the first quarter due to the significant drop in the share price during the quarter. Capital investment and operating costs in first quarter were also below guidance, as a result of the spending reduction efforts we have instituted as. As with G&A costs, there will be more significant impacts in future quarters. Apache’s adjusted production for the quarter was below our most recent guidance; reported gas production in the Permian basin was materially impacted by commercial arrangements at some gas processing plants, where the operator takes volume in kind as reimbursement for power costs. In lower gas environments like in the first quarter, the impact on reported volumes can be significant; in this case, approximately 24 million cubic feet per day. Permian oil volumes were also below guidance caused by the rapid reduction in activity due to the oil price downturn. As we look to the remainder of 2020, our full-year upstream capital investment program will be around $1.1 billion, approximately 60% of which will be in our international businesses. For the second quarter, upstream capital investment will be approximately $230 million, a sharp reduction from the first quarter. With respect to other typical guidance items, there are many uncertainties on a forward-looking basis. As such, we are not providing second quarter guidance and we are removing the full-year 2020 guidance, which we provided in February. In terms of production volumes, we are in the process of implementing a shut-in and curtailment program, which is already impacting second quarter volumes. The size and duration of this program will depend on many factors and is therefore difficult to forecast at this time. In closing, I would like to touch on our substantial liquidity position, our efforts to protect that position and how we will put it to use. When this downturn began, we quickly implemented actions to match spending reductions with the deteriorating oil price environment. As a result of those actions, Apache can achieve free cash flow neutrality for all of 2020 at an average WTI oil price in the low-30s. The original plan for 2020 required a WTI oil price closer to $50. Our goal is to achieve cash flow neutrality in order to minimize drawing on liquidity to fund our day-to-day operations. We entered this downturn with a tremendous liquidity backstop. We have a $4 billion revolving credit facility, which matures in March 2024 with a one-year extension option. Following our credit downgrade by S&P, we posted letters of credit for North Sea abandonment obligations utilizing a sublimit in the credit facilities specifically established for such purposes. This currently reduces the availability on the credit facility by $800 million. In terms of debt, one of our key financial goals for the year was to generate free cash flow to reduce leverage through debt repurchases. This remains a longer-term priority that is more challenging for the near-term given the price environment. Over the last two years, we eliminated $1.6 billion of debt in the near-term maturity window through paydown and refinancing efforts, leaving only $937 million of bond maturities over the next three years. Absent refinancing or retaining free cash flow to retire these bonds, we’ll use the revolver to pay them down. Conservatively, assuming all three years of debt maturities go on the revolver, we would still have $2.3 billion of remaining liquidity to manage through this downturn. In summary, we have taken significant and decisive actions to preserve liquidity, protect the balance sheet, and retain asset value for the future. These recent steps combined with those of the last few years give us sufficient capacity to bridge to a more sustainable and profitable price environment. And with that, I will turn the call back to John for some closing remarks.

Before we go to Q&A, I’d like to make a few comments regarding the durability of our production base in a reduced spending environment. As planned 2020 capital investment levels, our adjusted international production should be roughly sustainable from 2019 to 2020 on an exit rate basis. Assuming no material curtailments were shut-ins. In the Permian, where we have eliminated activity for the remainder of the year, the unknown magnitude, timing and duration of our curtailment and shut-in program makes it premature to provide a high confidence near-term outlook. I would note, however, approximately one-third of our Permian oil production comes from legacy vertical wells that have a base decline rate of around 10%, hits are over all Permian oil decline rate is significantly [Technical Difficulty] basin average. As we look ahead to 2021, our Permian decline rates will moderate and the capital investment required to sustain year-over-year production volumes will fall significantly. We will provide more details around future production as price volatility recedes and we have more visibility. I will now turn the call over to the operator for questions.

Thank you. [Operator Instructions] And our first question comes from Bob Brackett from Bernstein Research. Your line is open.

Hi, good morning, guys. I appreciate that you can’t talk in great specificity around the trajectory for Permian production, but can you kind of frame it in terms of what it could look like if you split out the legacy vertical versus kind of the shale? I mean just very wide goalposts as it were.

I mean, Bob, hope things are going well. I’d say in general, we’ve got two pieces there, and our conventional is a third of our oil production in the Permian. And as I said there at the end, it’s got kind of a 10% decline rate. The other two-thirds is unconventional, and I will say that we have been running a pretty flat pace. If anything, we moderated our activity pace in 2019. It was down from 2018. So, we’re going to be at a little lower unconventional decline rate, just because of the pace relative to our percentage as compared to most. So hopefully, that gives you a little bit more color on that.

And on that legacy vertical, are there any – what’s the inventory of wells that have just gotten to the point, where they’re not economic in sort of a two to three year recovery window? When would you abandon those? Or do you just not have that many in the portfolio?

Yes, I think, and I’m going to let Dave talk a few minutes on the process we’ve gone through on the shut-ins, because it’s something I’m – we’ve really put some time and effort into. But I think the important thing to know is, is that we’ve taken a very, very methodical approach. I think we’ve shut-in around 2,500 wells produce an average of about three barrels a day and about 150 barrels of water a day. We’ve done this in a way that we can kind of roll the wells and preserve the asset integrity. So, we feel pretty good about being able to bring those back, cost structures coming down. But we’re going to manage near-term for free cash flow and we think shut-in as long as it makes sense, but they wanted to give some color and climb maybe on the shut-in process that we’ve gone through.

Sure. Thanks, John and Bob, thanks for the question. And Clay, will jump in here in a second. But as John said, it’s a pretty robust process and it involves operations. It involves our production and reservoir engineers, our land team to understand the lease obligations, marketing to understand existing contracts and then our planning group and asset teams to really stress some of the economic parameters on the wells. John gave you some numbers on wells that are currently shut-in. We would anticipate as we go through May and into June those numbers likely increase, but you can see the kind of wells that were shutting in. There’s another bucket of wells is that when they break we’re opting not to fix them, and we’ve dropped our work over rig count by 80% since the beginning of the year and really tightened up the economic criteria in this market for those to justify working those wells over. And so the bucket that John talked about, most of those wells are wells that were overtly shut-in, but some of those are wells that we’ve opted not to repair. I think when you think about it, would any of these wells be permanently shut-in that that’s a function of longer-term price, but because we have a methodical process, because we have a reservoir production facility engineers involved in the process. We’re shutting these wells in, with the anticipation that they’ll ultimately be brought back online. So, we’re doing the right kind of chemical treatments before we shut them in and Clay can talk about that in a second. Some of the other considerations when you’re thinking about the economics here, wells that produce a little more gas than others, like to get a benefit in today’s gas market. And then when we think about our Permian exposure, we have some marketing agreements where a meaningful percentage of our Permian production goes to Corpus on the Epic pipe and are exposed to Brent link pricing. So, we have a number of considerations there. And finally from me, the other thing that we’re doing our subsurface teams of engineers and geologists have taken this opportunity to do some interference testing and some of our unconventional plays as we’re defining some production, we found historically that interference testing is one of the best ways to really understand well spacing and well placement in these three dimensional and conventional plays. We’re doing some of that starting imminently and again, we feel very confident that when things get better, we’re going to come out of this, a whole lot smarter than we were going into it. I had probably longer answered than you wanted, but I’m going pass it over to Clay to add some color.

Yes. sure, Dave. This is Clay Bretches and let me pile on a little bit with what Dave was saying and actually, add some color. Dave was talking about the shut-in wells and the reduction in work over activity and that is all true and that’s all something that, it was temporary until we bring those wells back on. In the meantime, while we do that, we have to make sure that we focus on preservation and so we make sure that we preserve and pickle the wells to reduce as much corrosion as possible. We also have to preserve the surface facilities and make sure that our tanks are preserved properly or rotating equipment is preserved so that when we do come back and flip that switch and it’s time to produce again, all of that production can come back on. And one of the things that we talked about, and John has alluded to this many times, a lot times in shut-in wells, especially for a long period of time, you have a lot of surprises when you turn them back on. Some of them are good and some of them are bad. The bad side and what can happen is you can end up with a lot of corrosion if you have not done everything in your power to make sure that you preserve those when you set them in. So, we’re taking great pains to make sure that preservation is going correctly. The next I wanted to talk about is cost structure. And in the opening remarks, John mentioned that we’re looking at a $300 million reduction, which is up two-fold from the $150 million that we had now announced a month earlier. And so I want to give some color on that, because most of this is permanent cost reduction and a change of the cost structure. You heard Steve talk about how we could operate as we go forward from what, prior to this great reduction in oil prices, it was a $50 oil world. We can go now to a $30 per barrel oil world. And so a lot of this has to do with the initiatives that we were already engaged in, about $150 million worth, which was announced after the end of the year. $150 million was largely G&A associated with our headquarters functions and with our various technical functions, in our offices, in our Houston, and Cairo and Aberdeen, Midland offices. But with the reduction in oil price, we had to take a lot of action to find other permanent cost reductions, and we did. So, what we see now are these permanent cost reductions, a lot of that has to do with field employee reductions, contractor reductions in the field, a lot of supply chain initiatives. Our supply chain group has been doing a great deal of work in order to get new contracts. And these contracts are more long lived than what we believe to be, hey, this temporary reduction in prices. And so we’ve been able to get some really good contracts, renegotiate those contracts and take advantage of the price environment that we’re in right now. And then the last thing I would mention, and I think this is really, really important, because this is a bottoms-up approach, but we went to our offshore installation managers, we went to our area operations managers in the field and the onshore, and we asked them for their initiatives, and how they could reduce costs? And how they can reduce costs in a meaningful way. And it was a very thoughtful process and a lot of work has been done to identify areas, where we can reduce costs, whether it means reducing redundant activities, reducing field offices automating processes that heretofore were more manual in nature. Those are the actions that we’re taking, and it’s led to this significant increase in these permanent cost reductions that we’re now pushing up to $300 million plus. So, I’ll turn it back over to John.

I appreciate that long thorough response. Thank you.

Thank you. Our next question comes from Charles Meade from Johnson Rice. Your line is open.

Good morning, John to you and your whole team there.

Good morning, Charles.

Yes. I appreciate that you guys probably aren’t – won’t, don’t want to speak about this. And don’t laugh at my pronunciation of the Kwaskwasi. I think that the one that’s currently drilling, but I wondered if you could – if there’s anything that you could – that you could offer about maybe, what you guys have continued to learn from your first two discoveries there offshore, Suriname, Maka and Sapakara West as you continue to analyze the – whether it be the course or the fluid samples or whatever else you might care to share.

Charles, thanks for the question. We remain very excited about turn-on. I think most importantly now that we’re two for two on both Maka and Sapakara from the wells, and actually, two for two in both the Campanian and the Santonian formations. We’ve proven, we’ve got an active hydrocarbon system. It’s the oil, with some gas condensate in some of the shower, campaigning zones in both Sapakara and Maka. But we’re very excited. You look at the distance between the wells are separate features. We’re now drilling Kwaskwasi is, you mentioned it is another separate feature. It’s actually in between the two. And then we will be moving back to Kwaskwasi for the fourth well, which is on the other side of Sapakara. So, I think it just shows, there’s not just one feature out there, we’ve got 1.44 million acres, the block is highly prospective. We’re only in two of water now, eight play types when things were going very well. So, we’re excited about, what’s in front of us. We’re currently working the plans with our partner, total on the appraisal program for Maka. We’re due to submit that to the government of Suriname later this month, which we will do. So, we’re anxious to kind of push forward there. We’re also working on the plans at Sapakara and it’ll fall sometime later this summer. So, we’re very encouraged. Things remain kind of on track and it was turning out to be everything that we hoped it could be. So, a very strong petroleum hydrocarbon system has got a long charge, that’s got locked charged.

Got it. Thanks. Thanks for all that detail, John. And then going back to your prepared comments, you guys just gave a really lengthy and detailed answer about these the shut-ins, but I just want to clarify something. When you talked about the rolling curtailments in your prepared comments, was that specific just to these 2,500 vertical Permian wells or is that also happening in other parts of your portfolio, whether it be horizontal Permian or international?

I mean, I think today Charles, we have around 2,500 wells shut-in all of the fields are going to be handled in a rolling way, and/or they’re going to be pickled and done very methodically. So, we’re working through that based on what we think is the best way to operate those. And so it’s a very methodical approach. As Dave mentioned, one of the things we’re also doing is, we’ve really thought through what data we can collect and how we can do it. I mean, you don’t have the luxury when you’re running a program sometimes of taking the time and doing the interference tests and the things that really help you understand spacing, and pattern alignment and so forth on the unconventional side. So, as Dave mentioned that as we get into June, the numbers going to grow a little bit. But a lot of the may stuff’s kind of already cast, but we’re taking a very bottoms-up, a very detailed approach and it will be designed to protect the wells and also learn as much as we can, because I think that’ll help drive our capital efficiency when we do kind of get back to work.

Thank you, John.

Thank you.

Thank you. Our next question comes from Doug Leggate from Bank of America. Your line is open.

Excuse me. Thank you. Good morning everybody. Hope everyone’s doing well out there. John I got a couple of follow-ups I guess to – maybe I’ll kick off with Suriname. Your – my understanding is, you’ve got 120 days from when you disclose the discovery to the governments that I would preview actually by right around now. So, I’m interested to know are we really end of the month, are we eminent? And can you give us some scope as to what you’re looking to do in the appraisal plan in terms of drilling or further interpretation of seismic or whatever that might look like?

Yes. actually, we’ve got the – the obligations are, we have 24 hours to make a discovery notice. And then we have 30 days to submit the official discovery report and then that clock starts. So, we actually are going to be the end of this month, Doug, when we – when we do submit the first plant. So, there’s actually the 30-day window between discovery and the official discovery notice is probably the 30-days that you’re missing in there. Yes, our partner and us are both continuing to do lots of things. As you know, with now two penetrations down on the seismic, there’s a lot of work we’re doing, which I think will be informative, a lot of reprocessing and things and will continue to do throughout the process. And really that some of the work we’re putting into the appraisal program is, how we design it to gain as much information as we need to make the proper decision. So, we’ll be in a position to submit something later this month to the government. And then they’ve got a 30-day period of respond back to us. So, it’s all systems go.

Well, thank you for closing the gap for me. The 30 days I wasn’t deed missing, but I guess if I could just try to, a little bit on this overview, at least is that you’re sitting on the depositional center here. Can you at least give us some idea of what the feature looks like relative to what we’ve seen next door? Because, I think there’s still some debate as to whether, there’s a viable development here. Is there anything, any color you can offer in that? Now, get on to the…

Yes. I would just say that the features are very large as always said. That’s why we’re working on the appraisal plans on how we want to appraise them. But the nice thing is they’re large and you’ve got obviously stacked pays, both that we’ve already discovered thus far in both the Campanian and the Santonian. So, it’s not disappointing in any way on that front and we’re excited about it.

My last one, if I may, is just changing geographies completely to Egypt. And one of the things that I guess continues to not get a lot of attention is the extraordinary expiration success rate you’re having there, 94%. I guess this last – last quarter run. Can you just walk us through what the go forward plan is in this lower oil price environment? And it may actually be a question for Steve, because I’m really interested to know how the PSC allows you to hold up your volumes in this very low oil price environment in the context of cost recovery barrel, legacy cost recovery entitlements that you have. So, any kind of column in the go-forward plan on the volume support you can get to the PSC would be helpful. Thanks.

Well, Doug thanks for noticing Egypt. Yes, we’re – you’re look at that program, I think what you’re saying is the early fruit from the acreage we picked up, the seismic we shot; we spent the last several years. In fact, we’re still shooting a very, very large acreage. We reshot a lot of our old existing seismic, the price – the previous shoot was done I think in 2013. So, a lot to change on that front and you’re seeing the fruits with some of the discoveries that we’ve announced this year, or we have infrastructure and tie in. We have some very, very impactful targets yet to drill that we’re excited about this year on the exploration front. And so what you’re saying is we’ve migrated the capital, we’ve ratcheted back a little bit in Egypt. It’s the area we’ve ratcheted back the least though, as we said on the international side. It’s also an area that we’ll want to put capital in, kind of first as you start to put capital back, because we’ve – just it’s what you’ve got is you’ve got six million acres, you’ve got multiple basins and the difference between it and an area like the Permian, you’ve got as much stack pay, but you’ve got conventional rock. And so that’s what differentiates it. The second thing I’ll say, and Steve may want to add some color, but these PSCs were designed and created in a much, much lower price environment. And so the way they work, things work very well in the price environment we’re at today. And so that’s how and that’s why Egypt continues to be an area that we can lean on. And that’s really one of the advantages to having an international portfolio. You’ve got rent, pricing, you’ve got the PSC structure and it’s not just the loan, unconventional treadmill that you have in the Permian. So, anything Steve, you want to add on the PSC?

Yes, I just, Doug, what I did is, I maybe point it to the supplement. We’ve got a page in there on the Egypt volumes that breaks it out pretty clearly. And what you’ll see is when you compare gross production volume to the net production volume that goes to the concession holders, us and Sinopec, we’ll find them. The vast majority of the barrels actually still go to Egypt, which is the way it ought to be when you’ve got a drilling program as John was talking about, that is just highly economic when you can – we can drill for the cost of these vertical wells and you get the types of oil rates that you can get out of Egypt. So, Egypt does end up with the vast majority of the volume, but what that does allow is that when you’re in a very low oil price environment, like today. We do get first call on cost recovery barrels. And so those barrels – some of the barrels moved from Egypt over to the concession holders in order to get cost recovery and cost recovery, it will vary. We’ve got 25, 26 some odd concessions there, different PSC contracts and all of them are slightly different from each other, but they’re pretty similar. And the way cost recovery works is during the period, which is a quarter – you will get full recovery through oil volumes or gas volumes for all of your in-period expense costs. And then you also get a quarterly share of amortization or depreciation if you will on historic capital. And the PSEs do vary slightly, but most of them are either a four-year or a five-year amortization of the capital spend. So, every quarter you do have a pretty significant hedging benefit from the PSC effect if you will, a built-in hedge. And so that’s why you see our adjusted barrels went up in the first quarter from fourth quarter, because of the price roll. you’ll see that again, most likely in second quarter from first.

That’s what I was getting at, Steve. could you put some order of magnitude on the bump given that oil price? can you give some order of magnitude to the bump given the oil price?

No. We’re not going to give that at this point in time. I think you could probably do a rough calculation of from fourth quarter to first quarter with your assumptions on what prices will be in the second quarter.

It seems that there’s a pretty big number. That’s why I was trying to get it from you. But guys, thanks so much…

So, very nice benefit of the PSC structure, it does, in a high oil price environment, it cuts the other way. Obviously it’s a double edged sword, but in the low oil price environment, it does provide a very nice natural hedge.

Got it. Thanks, guys.

Thanks, Doug.

Thank you. Our next question comes from Gail Nicholson from Stephens. Your line is open.

Good morning. I’m looking at the other permanent cost reduction that you guys discussed earlier in the call. Can you just talk about what the split between those is U.S. versus international and then the savings that achieved to date in the permanent cost reductions; have they been more skewed to one region than the other?

I’ll start out, Gail. A lot of those, we started – I mean we were fortunate in that we started kind of an operational redesign last September. So, we were six to seven months into a total revamping of our operating model, where we were closing some offices and really centralizing a lot of functions. What this enabled us to do in mid-March was just take a much, much deeper cut. And so a lot of those cost savings are going to be G&A related. They’re kind of across the board, a lot of it even on the corporate side. So, a big chunk of that is geared towards the overhead side and the G&A side. Secondly, the cost saving efforts have been kind of across the board, and I can let Clay give a little bit of an idea on the operational split, but you’ve got a lot in the Permian is we’re probably the lion’s share of that is, and then other things we’re doing in the North Sea and Egypt. I’ll say one thing with some of the COVID protocol that we put in place; we’re doing a lot more screening. We’ve kind of reduced down to critical folks that we need on the platform. So we’re actually adding some things in some areas too is, we’ve gone to a very specific approach, but any color Clay, you want to give on the splits.

now, I think you nailed it, John, as far as the order and where we’re seeing the biggest cost savings is U.S. being the largest, we saw a significant savings with the permanent closure of the San Antonio office and a lot of the reduction in expenses that we had in the NAUR region. But we also have seen a lot of reduction in expenses in the Permian basin excluding in NAUR. So, we’re seeing good reductions there. Same thing in the North Sea, we’ve had some reductions there as far as both headcount and contractor headcount that’s been substantial and ongoing. And then in Egypt, we’re really starting to pull the covers back on Egypt and understand that better. So, we think that there’s some low hanging fruit there that we can go after and attack. So, we’re not through cutting cost at this point. We think that there’s – there are other cost initiatives that that we can gain from and we’re working on that right now.

Right. And then…

Gail, it’s Steve, if I can give it a little bit more color on that as well. We talk about $300 million of identified sustainable cost reductions so far and that’s both in G&A and OpEx. And as John said, we had started the G&A focus last year. And so we’re ahead of the OpEx side. The OpEx started really in earnest with the oil price downturn. On the G&A side, G&A reductions so far are more than two thirds of the $300 million identified. G&A will include costs in the corporate center obviously, but also G&A related costs in the regions, and not to confuse things too much, but the G&A goes to three different buckets on our financial reports. A portion of it will show up in G&A expense on the P&L. Some of it shows up in LOE, because it’s allocated that way. And then some of it will go to the capital program. So, it’ll show up in capEx, but it’s all dollars of reductions and spends, regardless of where, where it goes. And then in addition to the sustainable reductions, which as I said, are approaching about $300 million identified. There will be some costs that we’ve identified and began the process of just deferring things that can just wait until a later point in time.

Great. Thank you for that incremental clarity. And then looking at the – in the quarter, you guys made a solid profit on purchased oil and gas. How should we think about this going forward?

Yes. so, this is the first quarter, where we have separated out the purchase – the sale of purchase oil and gas and the purchase costs of purchased oil and gas. And the reason for that is because this is the first time that it’s become material to our P&L and it’s become the cause of the pipeline – the long haul pipeline transport contracts that we’ve entered into. And this just gets down to the basics of how we run the business. We – the product that we produce, we sell in basin just as a general role. We sell all of the hydrocarbons in basin. We have a marketing organization, who amongst the many other things that they do. One of the things they do is they help us keep basin pricing connected to the larger broader market and we obviously had some events over the last few years that were disconnecting the Waha and El Paso Permian pricing from NYMEX Henry Hub, Houston Ship Channel type of pricing. And so the marketing organization recommended and we took them up on it of helping pipelines like GCX and PHP go from concept to FID and to reality with GCX now. So, we actually entered into contracts on those pipes and then we helped them get them get across the line. Of course, we also took an equity option, which Altus Midstream owns now in those pipelines, but getting those contracts – getting those contracts in place helped to help the pipelines get built. And in the marketing organization now manages are exposure to those transport contracts and what you see is the on our P&L now is the effects of the marketing organization purchasing product in basin or along the pipelines. It’s not necessarily at Waha or El Paso Permian, it could be anywhere along the pipeline or where they have access to the pipeline and then selling it at the other end of the pipeline or in other offloaded locations along that pipeline. And so they basically manage that exposure through purchasing and selling product. And since it is becoming material now, we need to separate that out and you see that the marketing organization made $22 million in the first quarter on that primarily, because of the differential promotion of the quarter between Waha and Houston Ship Channel.

Great. Thank you.

Thank you. Our next question comes from Michael Scialla from Stifel. Your line is open.

Good morning and thank you for taking my call.

Good morning.

This is actually [indiscernible] in for Mike. My question is a follow-up of a previous question on that 24 million cubic feet per day impact from a processing contract, and maybe, you could provide additional color into what am I look like going forward?

Yes. So, the most important thing to understand on that is that it has – it has no economic impact. So, we’ve got a contract, where we have to have gas processed to make it – to get it to pipeline spec. And we have a contract with a third party and then the third party charges us a fee plus power costs. And this is very typical of these types of arrangements, because power can be pretty variable costs. And in order to not take the risk of fluctuations and volatility and power costs, I just pass it on as a means of pricing the contract. And so what this – what this gas processor does with us and it did with many other parties too. Because like I said, this is a very typical term in these types of contracts. they take in kind portion of the gas that flows through the plant. And then they effectively take the revenue from that gas as payment of the power costs, and because of accounting rules, we can’t report that as produced volume, because it doesn’t belong to us. It effectively belongs to someone else. And so that’s the only reason why it’s just a – if we didn’t have this contract, this term, in this contract, we would report more volume, report more revenue, but then we would have an equal amount of more processing costs on the P&L, it has a zero financial impact.

Okay. So, it is expected to continue about the same amount going forward?

It’ll – it fluctuates with gas pricing. And so it’ll – if you can predict gas prices, then you’d be able to predict the volumes. It’s because gas prices got so low this quarter that the volume went so high. This will – this may, it occurred last year also in the Permian area and it certainly will occur in the future most likely, but it’s something, it’s not a norm.

Thank you. We’re going to take our next question from Jeanine Wai from Barclays. Your line is open.

Hi. Good morning, everyone. Thanks for taking our questions. My first question is on activity and maybe, trigger points for pricing, the operating cash margin in the U.S. continues to lag the North sea and just pretty, pretty meaningfully. And I know the U.S. is kind of a mixed bag of operating subareas. but at what oil price would you consider reactivating activity in the Permian? And we’re just asking because – the trigger price might be a little different for you than others given Apache’s strong international portfolio and maybe, wanting to maximize cash flow, because you’ve got to continue to fund Suriname and then you’ve also got the debt maturities coming due.

Jeanine, you actually answered your own question, but we will, I mean, if you think about our priorities of first thing I’ll say is, we will be slower to go back to work when we were shutting things down and we’re going to be very methodical with it. our priorities are going to be one, debt; two, would be dividend. As you start to think about capital, we’re going to continue to maintain the exploration and the appraisal program, and Suriname, Egypt would sit next and then you kind of get into the ducts in the Permian, North sea. And then we’d start thinking about the rig lines in Permian. the nice thing about our unconventional acreage is most of it, we don’t have any lease obligations. It’s not going anywhere. We’re not losing anything in that option. So, it’s all just a function of timing. And I think for us, we want to be very methodical. If you look back to how we kind of went back to work post the 2015, 2016 shutdown. And we’ve kind of been through this drill before as we went from 93 rigs before by second quarter of 2016 at that time period. We started the latter part of 2017 ratcheting back up and went to an eight-rig program and on the unconventional Permian side and we’ve been scaling back a little bit. So, I think we’d want to see higher longer deck and definitely, the advantages we have is the portfolio and we’re going to be managing cash flow. That’s it.

Okay. Well, really appreciate the detailed responses. That’s very helpful. My second question and the follow-up is regarding the debt maturities and adjusting those over the next three years. Do you have an estimate of what price oil needs to average in order to pay those off strictly out of free cash flow? And maybe, we’re just getting a little 2Q here. I know it depends on a ton of different factors that may not be known today. So maybe, an impossible question, but any commentary you might have around the free cash flow trajectory for Apache would be helpful. I know that you can pay the maturities in the revolver and you can fall back on that, but that might not be ideal.

Yes, Jeanine. Yes. We’re not going to give a lot of guidance or insights into free cash flow in the out years. All I’d say is in 2020, we are – we’re basically running free cash flow neutral with the current capital program. If you were running that at about $30 WTI, and so if you take the dividend, the reduction, the capital spending we’re on right now, the pace of capital spending we’re on right now, the cost reductions, the $300 million of cost reductions. and we’re at about a cash flow neutral WTI price of about $30. John indicated that reducing debt is certainly one of our highest priorities for future free cash flows. We’ve indicated in the past that our sensitivity to a dollar movement in oil prices is somewhere in the $50 million to $60 million range. So, you could probably use those and now get to a solution point on what the – what it might take to be able to pay down $937 million of debt over the next few years.

Great. That’s actually really helpful. Thank you very much.

Thank you. Our next question comes from Neal Dingmann from SunTrust. Your line is open.

Good morning. Just another one, you guys talked a little on Egypt and my question is more just on Egypt and North sea, specifically, just wanted, how do you guys think about maintenance caps there? I know that’s, you probably spending more there in Egypt and the maintenance cap, but I’m just wondering, could you talk about how you view that now as those become more efficient and potential free cash flow of each, let’s just use sort of the strip-ish prices?

Neal, when we look at those two areas, we’ve typically needed $700 million to $800 million or so to kind of hold them flat, combined. And those are – that’s net – our net portion of the – for the JV in Egypt for Sinopec. So, when you think about that, we’re slightly under that level this year with the reduction, we’ve shaved a little bit of that back, but as I mentioned, we’ve really high graded the inventory in Egypt and we’re seeing some strong results coming out of there. So that’s going to help us with that number. And then secondly, we’ve got the luxury of some, some really nice tie-ins and the timing of those that came on with our garden too well and so forth. And we’ve curtailed that well a little bit, given price volatility and things there. So, slightly under, but in kind of an improving picture in terms of what it takes to maintain those two areas.

Okay. And then just quickly move over to the permian, you all mentioned the release that you thought you’d have about 70 ducts. I’m just wondering, is there a sort of level that you’re comfortable taking this down to or just to before you’d bring rigs back or just wondering how you think about that count?

No. that number is just the result of where we were in the program and when we kind of picked up the range, I mean we – it was easier to shut down the completion crews. So that’s the first thing we did was shut the crews down. it took a little bit of notice time on the rigs as we mentioned. I think we’re on our last well on the Permian as we speak. And so that was purely just a result of kind of where we were. It’s more than we typically would carry, because of the shutting the completion crews down first, which is going to give us a little bit of ducts to bring on when we decided to put the comeback term. We’ll have about 15 in Alpine High in the restaurant, our Midland basin unconventional and for those are three mile laterals. So, it’ll give us some uplift when it’s time to put some capital back to work.

Great details. Thanks, John.

You bet.

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

Thanks. Hey, I appreciate all the color and I know you’ve been given a lot of bookends in terms of how to think about Apache here going forward, but just so I’m understanding it, I mean, the goal is you kind of go through 2020 and to 2021 at this point, based on your current activity level, it seems like you’re not spending at maintenance levels, when you talk about that $30 per barrel price sort of resiliency too. And I’m just curious, like, if you brought yourself to more of a maintenance production mode in each of the areas, what does that price indicator look like?

Well, I mean you’ve got the brackets there, Scott, because we were going to grow slightly with, where our budget originally was, which was geared around a $50 WTI. As we’ve said now, we can make kind of cash flow at 30, but we are going to decline, we’re below maintenance levels in the Permian. And so that will come down and international is going to be kind of flat or relatively flat. So, it’s somewhere in between there in terms of if you were going to call it, generate free cash flow and actually keep our volumes flat.

Okay. It’s fair enough. And obviously, in Suriname, you’ve got your – things you’re submitting to the government at this point in time. What can we expect from Apache over the course of this next year in terms of like how we’re going to hear new information and what the plan is leading into potential appraisals that once you get the government response back, you’ll have a press release or can you give us a sense of how you’re going to report the new information to us over the balance of this year?

Well, I mean, that’s something we’ll work through with our JV partner. I mean, typically, we – you submit the appraisal program; it’s kind of a work plan. And then we’ll go execute that. So, we’re not in a position right now with our partner, where we’re announcing what that entails. We’ve got a couple of years to do the appraisal program and before we have to make a decision on FID. And so we want to go about that as quickly as possible, but we’ve kind of balanced, you got to have to balance that as you get into the back half of this year, early next year with when you start.

Does the current oil price environment impact the FID decision at all much?

I mean, right now the good news is, is that you look at Suriname, you look at the timing of it you’re four to five years realistically from discovery to when you’d have production online. I think that all of us would look through to seeing a better price environment. I don’t know what the recovery shapes going to look like more near term, but I think as we would get out the timeframe, where Suriname comes into play and we’ve seen no wavering from our partner and we’re fully committed as well. So, I think it’s something that stays on track and it’s actually something that we can fund and our JV is beneficial to our capital profile spending.

Thank you.

Thank you. And in the interest of time, we’re going to take our final question from Brian Singer with Goldman Sachs. Your line is open.

Thank you and good morning.

Good morning, Brian.

Good morning. There’s been a bit of an improvement in expectations for natural gas prices into 2021 and I just wondered what it would take natural gas price wise, if anything to either shift or increase capital and the gas in your parts of the Permian, Alpine high or other areas within the portfolio?

Well, what I’ll say, Brian is it really boils back down to economics and the portfolio, right. So, it just goes to show you a year ago, we were talking about curtailing gas and here we are now curtailing oil in the basin. So, it just shows you how quickly things can change. We like having a portfolio, we like having a commodity mix. It gives us leverage, where we can put capital and have options, whereas if you’re saddled to it being a pure play in one commodity stream, that’s what you’re tied to. So, I’ll just say it’ll – the projects will have to compete as we start to put capital back to work and a lot of hinge on how the products are trading relative and what the view of them longer term is at that time. So right now, your gas, your wells and things have higher are more economic right now than the straight oil wells, which is a total flip from where we are.

Great. Thanks. And then my follow-up is with regards to a hedging strategy. Apache was unhedged in 2019 and into 2020, and I think there’s maybe a mischaracterizing, but that has been more of a preference to depend on the movement in capital spending versus the pluses or minuses of hedging. There have been some hedges that have been added recently and I just wondered if you can talk more philosophically about how – if there’s been any changes to how we should think about your hedging strategy going forward.

I mean, I think philosophically, no. We came into this on edge. We saw a lot of short-term volatility. And so we really put the hedges in place, swaps Q2, the callers and three and four of the few swaps in Q3, what we put those in is protection. to the downside scenario as you work through, what was a shutdown, but not a philosophical change, unless Steve, if there’s anything you want to add on the hedging.

Yes, sure, John. I’ll always take the opportunity to talk about our philosophy on hedging. So now, it hasn’t changed, Brian. We believe that the best hedge is the ability to have flexibility in your activity. I think that current price environment proves that. So, we think the best hedge is the ability to ramp down activity, which is what the industry needs to do right now and associated with that to get cost levels down as low as possible. There are times when we do believe, we need to engage in hedging activity. We had one of those in the past when we had commitments that couldn’t be avoided, where we had to build out the midstream at Alpine high. We’ve got one now, where you’ve got a period, where oil prices are getting into a range where cost just can’t be cut low enough to maintain free cash flow. And so that’s why we entered into the hedges as we saw what was happening. We knew second quarter was going to be very, very painful. You could see that coming and that’s why we hedged the vast majority of our volumes for second quarter, mostly with swaps, all with swaps. And then we hedged a little bit less for 3Q and even less still for 4Q. And there has been a combination of swaps and some collars. So we just – we generally just believe that we have a preference to refrain from financial hedging. We, as I spoke about earlier with the Egypt and coming in the future of the Suriname, we do have some natural hedges already in the portfolio and it’s – I’ll just point out that nobody ever asks us why we didn’t hedge after prices run up. I only ask when prices have run down. just I’m sure just one of those oddities of the environment that we’re in right now.

Thank you.

Thank you. And that does conclude the question-and-answer session for today’s conference. And I’d like to turn the call back over to John Christmann for any closing remarks.

Yes. Thank you, operator. In closing, I would like to wish all of you good health as we work through this COVID-19 pandemic. We are looking forward to getting the economy back on its feet and sharing our progress in future calls. Now, back to the operator to close.

Ladies and gentlemen, thank you for participating in today’s conference. This does conclude the program. You may all disconnect. Everyone, have a wonderful day.