阿帕契 (APA) 2023 Q3 法說會逐字稿

Good day, and thank you for standing by. Welcome to the APA Corporation's Third Quarter 2023 Results Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Gary Clark, Vice President of Investor Relations. Please go ahead.

Good morning, and thank you for joining us on APA Corporation's Third Quarter 2023 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 and outlook. Also on the call and available to answer questions are Dave Pursell, Executive Vice President of Development; Tracey Henderson, Executive Vice President of Exploration; and Clay Bretches, Executive Vice President of Operations.

Our prepared remarks will be about 10 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 financial and operational supplement, which can be found on our Investor Relations website at investor.apacorp.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 noncontrolling interest in Egypt and Egypt tax barrels.

I'd like to remind everyone that today's discussion 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'll turn the call over to John.

Good morning and thank you for joining us. On today's call, we will review Third Quarter highlights, discuss our outlook for the fourth quarter and provide a high-level overview of our capital plan and anticipated production in 2024. For the third quarter in a row, adjusted oil production exceeded the high end of our guidance range. Good execution and strong well performance in the Permian are the primary drivers of this trend. We also achieved the high end of our guidance in the North Sea during the quarter, which benefited from the production ramp of the Storr North well.

In Egypt, gross oil volumes grew by approximately 4,000 barrels per day which was a bit below expectations as previously disclosed. On a total company basis, third quarter reported oil volumes were up more than 15% from the same quarter in the prior year and we are very pleased with this progress.

Activity in the U.S. and Egypt remained steady, while we suspended drilling activity around midyear in the North Sea. Our investment program in the North Sea is now directed towards safety, base production management and asset maintenance and integrity.

In Suriname, we achieved a very important milestone during the third quarter with the completion of a successful appraisal drilling program at Krabdagoe on Block 58 and the subsequent announcement by our partner, TotalEnergies, of plans to proceed with FEED work for a 200,000 barrel per day FPSO in the eastern portion of the block. The planned oil hub is underpinned by an estimated 700 million barrels of recoverable oil resource at Sapakara and Krabdagoe and has targeted FID by the end of 2024.

Turning now to our outlook. In yesterday's financial and operational supplement, we issued fourth quarter guidance, which anticipates slightly lower production on a BOE basis compared to the third quarter. The primary contributor is in the North Sea, where the temporary shut-in at Beryl Bravo will result in volume deferrals of about 5,000 barrels of oil equivalent per day.

In the U.S., completion timing will lead to a relatively flat quarter, consisting of unchanged oil production and a small decline in natural gas. And in Egypt, a combination of higher oil and lower natural gas volumes should deliver BOE growth, but not enough to fully offset the downtime in the North Sea.

Let me provide a bit more color on production operations in Egypt. In February, we established a gross oil target of 154,000 barrels per day for the fourth quarter. We now estimate that number will be closer to 150,000 barrels per day, which is up about 5,000 barrels per day from the third quarter. After successfully working through the challenges associated with ramping our rig count from 11 to 18, our drilling program is now performing as planned. However, we have experienced a growing backlog of workover projects over the last 2 quarters and a corresponding uptick in barrels off-line.

To address this, we have begun to increase our workover activity, which Dave can discuss further in Q&A.

During the fourth quarter, we are opportunistically accelerating the completion of 8 Permian wells from January into December and adding a sixth rig in the Delaware Basin. This will result in an increase in our estimated fourth quarter upstream capital to around $500 million and bringing full year upstream capital to just under $2 billion. I should note that these investments will not have a material impact on fourth quarter production.

As we typically do at this time of year, I would like to provide a high-level overview of our 2024 outlook which we will follow up with formal guidance in February. Recall that we entered 2023 with a planned upstream capital budget of $2.0 billion to $2.1 billion. As of today, we expect a similar range in 2024, albeit with some changes in regional allocation. We are targeting low single-digit oil production growth next year with expected increases in the Permian and Egypt, more than offsetting declines in the North Sea.

APA remains committed to returning at least 60% of our free cash flow this calendar year to shareholders. During the first 3 quarters of the year, we generated $673 million of free cash flow, 65% of which we return to shareholders via dividends and stock buybacks. This leaves more to do in the fourth quarter, and we will fulfill our minimum 60% commitment for the full year.

One of APA's core principles is to produce oil and gas safely and to reduce the environmental impact of our operations. I am pleased to announce that we recently achieved an important milestone in reducing methane emissions with the conversion of over 2,000 pneumatic devices in the Permian to lower emitting technologies. Our programs to identify and eliminate emissions throughout our global asset base are ongoing, and we continuously seek to expand and improve them.

In closing, we are committed to our strategy of maintaining a diversified portfolio and maintaining operational flexibility to respond quickly to commodity price volatility and other externalities. We are demonstrating this today through the reallocation of capital from the North Sea into the Permian and Egypt. We also remain committed to the investment in a portfolio of exploration projects, which have the potential to drive differentiated future growth and competitive full cycle economics. And with that, I will turn the call over to Steve Riney.

Thank you, John, and good morning. For the Third Quarter, under generally accepted accounting principles, APA reported consolidated net income of $459 million or $1.49 per diluted common share. As usual, these results include items that are outside of our core earnings. The most significant of which was a $93 million release of a valuation allowance on deferred tax assets. This was offset by a loss on the quarterly mark-to-market of our Kinetic stock ownership and unrealized derivative losses on our Waha basis swaps. Excluding these and other smaller items, adjusted net income for the third quarter was $410 million or $1.33 per share.

Free cash flow, which for external purposes excludes changes in working capital, was $307 million in the quarter. Through dividends and share repurchases, we returned 32% of this amount to shareholders during the quarter. As John indicated, year-to-date, we have returned 65% of free cash flow to shareholders. Please refer to APA's published definition of free cash flow for any reconciliation needs.

In our 3Q earnings pre-release, we anticipated G&A expense would be significantly higher than our underlying run rate of costs which is around $100 million. For the quarter, reported G&A was $139 million, mostly because of APA stock price appreciation and the mark-to-market impact on previously accrued share-based compensation.

As we have explained in the past, the mark-to-market of share price movements also impacts LOE, CapEx and exploration expense. Thus, these items were also higher during the third quarter for the same reason.

North Sea taxes also came in above guidance in the quarter by $46 million. This was the result of an incremental cargo lifting late in the quarter, which was not anticipated at the time we provided 3Q guidance in August. In accordance with Generally Accepted Accounting Principles, we recognized cargo liftings in the quarter they occur, which increases revenue and current tax expense, but has no impact on reported production volumes.

To be clear, though, this is just a movement of revenue and income tax expense from the fourth quarter into the third quarter and has no impact on our anticipated full year North Sea production revenue or income tax expense.

As previously noted, our Cheniere gas sales contract commenced on August 1 and contributed 2 months of free cash flow in the third quarter. You will find this impact on our P&L in the 2 line items, which capture the revenue and costs associated with oil and gas purchased for resale.

In the third quarter, the Cheniere contract contributed free cash flow and pretax income of $32 million. We currently anticipate it will contribute approximately $90 million in the fourth quarter and $375 million for the full year 2024.

In closing, as anticipated, the second half of 2023 is poised for improving production and free cash flow versus the first half of the year. With the improving performance, we are tracking very close to our original full year guidance across most of our key financial and operational metrics for the year. We will continue to return capital to shareholders through dividends and share repurchases. And while our balance sheet is much stronger than a few years ago, we continue to recognize the need for further progress on debt reduction. And with that, I will turn the call over to the operator for Q&A.

(Operator Instructions) And our first question comes from Doug Leggate with Bank of America.

I think Gary just lost a bet on name pronunciation, but thanks for getting me on. Guys, the North Sea, I wonder if you can offer a little bit of color on what you see as a decline curve there with no capital. And where I'm going with this is, obviously, you've got, I believe the gas compressor, these are old assets, I guess you're having to take it off the platform and so on. That's going to come back. And obviously, production will decline because you're not spending any money. But my question is, how does the decline look versus the free cash flow in the North Sea. It strikes me that the free cash flow in a declining curve could actually be higher.

Yes, Doug, it's a good question. We're in the process right now working through the 2024 plan. Clearly, we've got some downtime that we've announced in the North Sea in the fourth quarter as we do have a compression that we had to haul onshore. We'll get that back on sometime early next year. And then you'll be back at your base decline both for [40s] and barrel. 40s you know is under water flood. So it's got a much lower decline than barrel, but we do not have the rig. We'll continue to focus on maintenance integrity projects. It will come back early next year with a detailed look when we give out the '24 plan.

But is it fair to say that versus 2023 when you were spending capital, that free cash flow could be higher, John?

I think it's early on the...

Yes. Doug, yes, I think it's -- as John was about to say, I think it's a bit early to state that for 2024. It's certainly a possibility. But let's get to February, we'll have a detailed plan and we'll know kind of what type of price environment we're looking at as well. And we'll have a better analysis on that at that point in time.

All right. John, my follow-up is on Suriname. I managed to get a red eye to Total's Analyst Day this year. And I asked Patrick, a very specific question about timing. And I wanted to get your perspective on this. My understanding is that the 2028 schedule for first oil assumes a 42-month newbuild FPSO, but since that announcement, I understand that SBM has been selected with an early [hull]. In other words, a year earlier on that time line with some 70% expected to be contracted at the time of FID. I know you're not the operator, but I wonder if you could confirm or offer any color around those points.

Yes. I would just say for now, I mean, kind of the official time line is FID by the end of '24 and first oil by 2028. But obviously, there's incentive and motivation to try to accelerate that. And I would expect that they will do everything they can to do so.

Stand by for our next caller, and that is John Freeman with Raymond James.

Yes. The first question I had on the 6th rig that's getting added in the Permian [role]. Is the plan for that rig to operate exclusively in the Delaware or potentially toggle between Delaware and Alpine High?

John, it's a spot rig. We're picking up. It will kind of go pad to pad. It will start in the Delaware on some oil pads. But then there's flexibility, and we'll come back in February with a little more detail, obviously, on the 2024 plan and how that would sit.

Okay. And then just my follow-up question. I appreciate the preliminary sort of outlook on 2024. If I take kind of what you said about the budget being in kind of flattish versus '23. And I think about like the 6th rig, that's largely kind of funded with the North Sea CapEx reduction. And then Egypt, you've said previously is kind of status quo next year. And so it seems like just of your 3 main operating areas, that's kind of flattish and the wildcards kind of exploration, was your commentary about kind of a flattish budget. Does that -- is that all in? Does that include the exploration side? If you can kind of just walk us through kind of how you see the expiration in a year where there's probably a step down in activity and turn on ahead FID.

Yes, John, it's a great question. Yes, it includes about $150 million of exploration. I think you laid it out pretty accurately. You'll see a full year without drilling in the North Sea, you'll see an increase in the Permian, relatively stable drilling lines in Egypt. And you will see about [100.5] in terms of explorations that we're sketching out at this point. So relatively stable program with continued exploration investment like we've done over the last several years.

Our next question comes from Bob Brackett with Bernstein Research.

You talked about in terms of the Permian. If we think about 12 net completions in 3Q, you're kind of driving flat production Q-on-Q and 4Q. 20 net completions in 2Q allowed you to grow the following quarter. And it sounds like you've already connected 12 wells in October with 18 coming in the rest of the queue. Does that imply a pretty strong cadence into sort of 1Q of next year in terms of the Permian?

Yes, it's a good question, how timing of completions drives the quarterly production cadence. This is Dave Pursell, by the way. The remaining completions this quarter will be weighted more towards December. And then we'll provide you in February with what the cadence of completions looks like in '24. And as you can imagine, there'll still be some lumpiness, and we'll provide that in February once we get the plan finalized.

Okay. A quick follow-up. If there is an FID in '24 around Suriname, does that change that CapEx budget of 20 or 21 or it's kind of a rounding error?

No. At this point, we factored that in, Bob.

Our next question comes from Neal Dingmann with Truist Securities.

John, my first question is just on Egypt. I'm just wondering if the '24 plans will continue to have sort of a similar level of exploration and development activity? And if so, should we assume somewhere around, I mean, in your estimate, around that sort of same drilling success next year?

Yes. Neal, program will be pretty stable. We're running 18 rigs in Egypt, it is a steady diet of both development and exploration and I anticipate that to be very similar next year. And we do expect to be able to continue to show good growth in Egypt.

Very good. And then my second -- John asked a little bit on this, but just on the Permian gas plans. I'm just curious if your decision, if and when to go back and boost that activity, is that based more on how those gassy well economics compete against your oil Southern Midland or Delaware economics? Or is it just simply if those gas returns would drive a certain rate of return.

Yes. I mean it's really more a function of stability in the Waha pricing. And the wells we've drilled this year have been strong and very competitive. I mean I think a $3 Waha, they're very, very competitive with Permian oil. So -- but it's really more a function of when we believe we'll have stability there at Waha that you can produce them into the infrastructure.

Our next question comes from Scott Gruber with Citigroup.

Just coming back to Egypt. You mentioned growth next year. Is that going to be on a year-over-year basis? Or do you think the exit to exit will be up as well?

Yes. We'll give you the details when we roll out the plan in February, but we'll show growth. We'll show growth most likely year-over-year in exit, but let us give you those details in February.

Okay. And then just thinking about the next few years, you have a project that will be moving forward in Suriname. And obviously, you have the carry from Total, you still have $1 billion or so of commitments. Could you just speak to whether that impacts your capital allocation across the rest of the portfolio on a multiyear basis?

Yes. I mean we look at the multiyear plan, and that's the beauty of the carry is it's going to keep it very, very manageable place from where we've been. So I mean we basically structured that deal, banking on success, and you'll see that start to follow through if we move through the next phases. So we got FID a project first. But that's for the carry to kick in.

Our next question comes from Roger Read with Wells Fargo Securities.

Just to follow up. Egypt, you had a little release of capital -- for working capital this quarter. Just how do you think that looks going forward? And also in Egypt, given that they've had some gas issues related to imports in the [Med], any interest or pressure from Egypt to have you increase gas production there? Or is that something that could occur in '24 or that's not really a reasonable assumption given locations of fields and takeaway capacity, et cetera.

I mean there's no doubt Egypt needs more gas production. We're flowing everything we can into the grid, which is where our gas goes. Our program has been focused on oil as we received 265 per MMBtu there. But short term, there's not anything we could do to increase gas production, but there are some longer-term projects, but would need to work on a higher gas price there.

And on working capital, what...

On the working capital, this is Steve. So we did have an increase in working capital in the quarter in Egypt, as you will see in the supplement. So the receivables did go up during the quarter, but receivables from EGPC actually went down during the quarter. And if we go back to first quarter of this year, when I think the concern about the payments from EGPC kind of surfaced at that point in time with the first quarter results in May. Since that time, from first quarter -- in the first quarter to the end of the third quarter, EGPC receivables have gone down and so have the past due receivables from EGPC.

So I think we're in good shape there. We've made -- making progress. We've made some good progress. And as John always says, we're in constant contact with the highest level folks in Egypt about managing that receivable balance. So we're in -- we're making some good progress there.

More to go, but we're making good progress. I think the issue with -- or the reason why receivables went up in the third quarter is because we were exporting more cargoes than selling them to third parties. And those third-party receivables have gone up during the quarter because we were third-party receivables were low at the end of the second quarter and higher at the end of the third quarter. So those are receivables that are just paid under normal terms from our normal credit-worthy and on-time paying purchasers of the oil coming out of Egypt in export cargoes.

And in that situation, just normal seasonal or month-to-month kind of change, nothing to read into that, presumably.

Right, right. And you'll see there's a -- at the corporate level, not just in Egypt, but at the corporate level, there's a meaningful increase in working capital during the quarter, and that also is just seasonal type things. We had some payables in particular, a large one around taxes, a large cash payment and taxes in the U.K. that comes in the third quarter. And so a lot of seasonality to working capital movements for the company as a whole.

And our next caller is Charles Meade with Johnson Rice.

This is Michael Furrow actually filling in for Charles Meade. Just one question for me regarding Suriname. I know FID is not expected until late in 2024, and this might be a bit premature, but when do you think that further exploration could occur within Block 58? And I recognize that Total is the operator here. So maybe a better way to frame it would be when would APA like to further explore Block 58. And maybe it will be glad if you could even speak on Block 53.

No, it's a great question. The focus this year was appraisal of Krabdagoe, so we could start a project in terms of getting it moving into the next phase, and we're in a position to do that now. We do see several high-quality, low-risk prospects in Block 58, a lot of the program at Krabdagoe that obviously appraised, that fairway also derisked in our mind, a lot of prospects. There's no urgency in terms of getting to them in '24 but we will be working through those with our partner.

And when I look at the 2 blocks, we see more prospectivity in 58 over 53. We're working with our various partners there on the next steps at Waha. But I think there's -- we would see more prospective in 58 over 53 at this point.

And our next question is from Scott Hanold with RBC Capital Markets.

My question is going to be on just general exploration. I mean, obviously, you got Suriname going on. But more recently, you've kind of farmed in a position in Alaska and on top of that, obviously, you've got different things in Uruguay and Dominican Republic. Can you tell us, in general, just first, maybe starting with Alaska and then how you think about these other prospects moving forward for APA?

No. Alaska fits our exploration strategy, and that is trying to build a high-quality portfolio. We've got a proven operator in state lands, very, very prospective acreage, and it's something we look forward to sharing more in February. And it's all about a portfolio on the exploration side and having choices to high grade and drill the best things that are going to create the most shareholder value.

So when I think of APA and look, I mean, it seems to be in contrast with some of, I guess, your U.S. or even just E&P peers where there's a lot of, I guess, M&A going on there for domestic shale, but it looks like APA's take a little bit different angle or is there still a desire to potentially maybe even bulk up in the Permian or other focus areas where you do have more, I guess, proven production at this point?

Yes. I mean I think we like to look at both avenues, both the organic and the inorganic and we stayed committed to an exploration program, and you're seeing that pay off in the Suriname and longer term, but I also think you saw us last year bolster some acreage in the Delaware. So it's a diet of both that you're constantly looking at. And you've got to continue to focus on adding to the assets as well as what can create value for your shareholders.

So when you look at the Permian Basin, do you all feel with the 5, 6 rig pace you've got, what you'd say, ample inventory of kind of Tier 1 stuff?

Yes. I mean I think with where we sit today, 5 to 6 rigs, David said end of the decade pretty easily, and that's focused on higher quality, longer laterals, and we're always -- we've got a nice footprint. There were always moving inventory from one category of -- up into the high grade as we continue to test and find ways to make it all work.

Our next question comes from David Deckelbaum with TD Cowen.

John, I wanted to just ask, are you able to tell us the $150 million you have earmarked for exploration next year, I guess, to be more pointed about it, how much of that is included for ex-Suriname exploration?

At this point, we'll come back with more color next year on the program. We've -- it's a placeholder, and we're working through. There are some other things we'll be doing. You've got exploration in Egypt that we've always funded and some other things, but we'll come back with more color in February.

Appreciate that. Maybe if I could just follow up on Egypt. You talked about the growth trajectory in the next year, and I certainly know that U.S. oil is anticipated growing next year. Can you give a little bit more color just on what's happening with the increased workover activity? What's driving that? And are there any alterations being made that this won't be a drag into next year? Or is this being factored in with greater frequency now that you have this increased rig count?

Yes. I mean it's a situation where we've always had, I'll call it, wells or a volume offline that requires workover. We have a lot of [subforms] in Egypt, and we've had some increase in the failures in a few areas, and that number has ticked up. And Dave can get into some more color, but we've just got more barrels off-line that we need to get to on the workover side and we're addressing that. So it's something we're jumping all over.

Yes. And so just to follow on what John said, we've -- we're working on a root cause analysis just to understand, are we seeing a structural change in well failures. We've seen a reduction in ESP run times and -- but we're doing a broader look at that. And to put some numbers on John's comment on base level of workover inventory, that typically represents about 5,000 barrels a day of production that's offline at any given time. We've seen that increase to over 10,000 barrels a day really from the end of the second quarter through today. And so we've added a workover rig, and we're doing some other things to start working that backlog down over time.

Is that in coincident with where you're developing right now? Or is it just circumstantial to just across the entire area.

It's across the entire Western Desert, and we're working the root cause on that just to understand, are there any specifics. But right now, we haven't identified any.

(Operator Instructions) And our next question comes from Leo Mariani with ROTH MKM.

I just wanted to follow up briefly on Egypt here. I think you guys maybe added a rig recently. I think you were at 17 earlier in the year, if I sort of got it right. So -- just curious, is that just because of lower North Sea activity or just kind of reallocating dollars here? And then, I guess, just in general, obviously, there's been significant instability there kind of in that Sinai Peninsula area, bordering Israel there. With the conflict that's happening right now, I mean do you guys have any concerns over potential spill over with Egypt and have you been kind of in contact with the Egyptian government regarding that?

Yes. It's something that -- it's interesting. We're coming up on our 30th anniversary of being in Egypt. So we've got a great history there. We've been there a long time, and we've been through -- watched Egypt go through a lot of trying times. This year has been difficult for them, and it's really been driven more by inflation and currency devaluation and some of those factors. We're closely monitoring the situation. I think the good thing from our perspective is our operations are all West to Cairo into the Western Desert. And if you go back in history, even over the air of spring, we have not had any shut-ins or major interruption in our operations. So I think the good news there is, as the government continues to prioritize oil and gas operations, they know they need the in-country production. And we've been watching things very, very closely.

Okay. That's helpful. And then in terms of the $150 million in exploration next year, I don't want to beat a dead horse here but as you kind of look at a high level, in your mind, does that include some dollars in Suriname at this point? Or is that just sort of kind of still an open-ended proposition?

It's in general, right now, it's a placeholder for the things we want to do. But there's [seismic] that is being shot in Suriname in the -- where would be the development area, some other things. So it will capture our exploration spend for next year and we'll come back with more details in February.

And our next question comes from Geoff (inaudible) with Daniel Energy Partners.

Really, my question is around U.S. oil production, which looks like it's taken a pretty impressive step change up. I mean, obviously, you completed some more wells, but obviously, several quarters where it was just kind of locked into the 70s. Now we've taken this 8,000 barrel a day step up in Q3. And I'm wondering, a, what changed and b, if there's something that's happened that has kind of prompted this decision to add another rig in the Delaware.

No. I mean, it's really just a continuous program. I mean we're seeing the benefit of the deliberate approach we've taken, we've been focused on long laterals and really locking the rig lines down and given the team's time to execute. And you're seeing that. We've continued to drill long laterals, and we're continuing to have good results. It's really just a function of the timing of the completions.

In terms of adding the 6th rig, it's really more allocation of capital from the North Sea into the Permian and -- but we look forward to continuing to deliver strong results. And if you look, fourth quarter is a little flattish compared to third quarter. A lot of that is because third quarter is running ahead versus fourth quarter running behind. So very, very pleased with the execution level in the U.S.

I am showing no further questions at this time. So this concludes the question-and-answer session. I would now like to turn it back to John Christmann, President and CEO, for closing remarks.

Yes. Thank you for participating on our call this morning. I want to leave you with the following thoughts. We've completed a successful appraisal program in Suriname, at Sapakara and Krabdagoe and will advance a project through the FEED process during 2024.

In Egypt, gross oil production continues to increase on the success of our drilling program and lastly, we continued to deliver outstanding results in the Permian, where we've added a 6th rig, which will add to the momentum as we enter 2024. We look forward to telling you more about things in February, and thank you for the call.

And this does conclude the program. You may now disconnect.