APA Corporation (APA) — Q3 2023 Earnings Call Transcript

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 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 non-controlling 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. The 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 mid-year 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 Krabdagu 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 Krabdagu and is 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 Brae 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 two quarters and a corresponding uptick in barrels offline. 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 eight 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 bring 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 three quarters of the year, we generated $673 million of free cash flow, 65% of which we returned 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 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 Kinetik 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 prerelease, we anticipated G&A expense would be significantly higher than our underlying run rate of cost, 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 recognize 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 two months of free cash flow in the third quarter. You will find this impact on our P&L in the two 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 pre-tax 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.

Thank you. 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 declining curve there with no capital. And where I'm going with this is obviously you've got, I believe the gas compressor. These are all the 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 compressor 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 Forties and barrel. Forties is underwater flood, so it's got much lower decline than barrel. But we do not have the rig. We'll continue to focus on maintenance integrity projects and we'll come back early next year with a detailed look when we give out the 2024 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.

Yes, Doug. I think it's a bit early to make any statements about 2024. It's certainly a possibility, but let's wait until February. By then, we will have a detailed plan and a clearer understanding of the price environment we will be facing, along with a better analysis.

Thank you. John, my follow-up is about Suriname; I attended Total's Analyst Day this year and asked Patrick a specific question regarding the timing. I would like your perspective on this. My understanding is that the schedule for first oil in 2028 assumes a 42-month new build FPSO, but since that announcement, I’ve learned that SBM has been selected with an early hull. This means a year earlier on that timeline, with around 70% expected to be contracted at the time of FID. I know you're not the operator, but could you confirm or provide any insight on these points?

Yes. I would just say for now, I mean kind of the official timeline is FID by the end of 2024 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.

Fair enough. Thanks, guys.

Yes. The first question I had on the sixth rig that's getting added in the Permian well 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'll 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 a kind of flattish versus 2023, and I think about like the sixth 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 three main operating areas that's kind of flattish and the wild cards kind of expiration. Was your commentary about kind of a flattish budget? Is that all in? Does that include the expiration 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 concern on ahead of FID?

Yes, John, it's a great question. Yes, it includes about $150 million of expiration. 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 million in terms of expiration is what we're sketching out at this point. So relatively stable program with continued exploration investment like we've done over the last several years.

Yes. Good morning. You talked about in terms of the Permian; if we think about 12 net completions in 3Q is kind of driving flat production QonQ in 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 2024. 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. Quick follow-up, if there is an FID in 2024 around Suriname, does that change that CapEx budget of 2.0 or 2.1 or it's kind of a rounding error?

No, at this point, we've factored that in, Bob.

Thanks for the time. So my first question is just on Egypt. I'm just wondering if the 2024 plans will continue to have sort of a similar level of exploration development activity. And if so, should we assume somewhere around I mean in your estimate around that sort of same drill and success next year?

Yes. Neal, program it will be pretty stable. We're running 18 rigs in Egypt and 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 decisions if and when to go back and boost that activity. Is that based more on how those gassy well economics compete against your oily Southern Midland or Delaware economics or is it just simply if those gas returns would provide a certain rate of return?

It's primarily about achieving stability in the Waha pricing. The wells we drilled this year have performed strongly and are very competitive. At $3 at Waha, they are highly competitive with Permian oil. The key factor is when we anticipate having stability at Waha to enable production at the end of the infrastructure.

Thanks. Can you 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 rollout the plan in February, but we'll show growth most likely year-over-year end exit. But let us give you those details in February.

Okay. And then, just think about the next few years. You have a project that would be moving forward in Suriname and obviously you have the carry from Total. You still have $1 billion or so of commitment. Can you just speak to whether that impacts your cap allocation across the rest of the portfolio on a multi-year basis?

Yes. I mean we look at the multi-year plan and that's the beauty of the carry is it's going to keep that in a very, very manageable place from where we've been. So I mean that 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 got to FID a project first, but that's where the carry will kick in.

Yes. Thanks. Good morning. Just to follow-up Egypt had a little release of capital or 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? Is that something that could occur in 2024? That's not really a reasonable assumption given locations of fields and takeaway capacity, et cetera.

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 receive 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 we would need to work on a higher gas price there.

And on the working capital thoughts?

Yes, we experienced an increase in working capital in Egypt during the quarter, as reflected in the supplement. While overall receivables increased, receivables from EGPC actually saw a decline. Looking back to the first quarter of this year, concerns about payments from EGPC arose at that time with the first quarter results in May. Since then, from the end of the first quarter to the end of the third quarter, EGPC receivables and past due receivables have both decreased. I believe we are in a solid position and have made significant progress. We are in regular communication with top officials in Egypt regarding the management of that receivable balance. Although there is more work to be done, we are making good strides. The increase in receivables during the third quarter is primarily due to higher exports rather than sales to third parties. Therefore, third-party receivables have risen since they were low at the end of the second quarter but increased by the end of the third quarter. These receivables are from our reliable customers who pay on time for the oil exported from Egypt.

And that's in that situation, just normal seasonal or month-to-month kind of changes, nothing to read into that percent of that.

At the corporate level, there has been a significant increase in working capital during the quarter, not just in Egypt. This is mainly due to seasonal factors. We had some payables, particularly a large cash payment in taxes in the UK that occurs in the third quarter. Therefore, there is a lot of seasonality to working capital movements for the entire company.

Hi, good morning. This is Michael Furrow actually filling in for Charles Meade.

Hello, Michael.

Hi, okay, just one question for me regarding Suriname. I know FID is not expected until late 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 if you could even speak on Block 53.

No, it's a great question. The focus this year was appraisal of Krabdagu, 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 Krabdagu that obviously appraised that fairway also de-risked in our mind a lot of prospects. There's no urgency in terms of getting to them in 2024, but we will be working through those with our partner. And when I look at the two blocks, we see more prospectivity in 58 over 53. We're working with our various partners there on the next steps at Baja, but I think we would see more prospectivity in 58 over 53 at this point.

Yes. Thanks. 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?

Alaska fits our exploration strategy and that is trying to build a high-quality portfolio. We've got a proven operator, its 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 is taking 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 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.

When you consider the Permian Basin, do you believe that operating at a pace of five or six rigs gives you sufficient inventory of high-quality resources?

Yes. I believe that with our current position, operating five to six rigs is quite feasible as we move further into the decade. Our strategy focuses on higher quality and longer lateral drilling. We have a solid footprint and are continuously shifting our inventory from lower categories to higher grades as we experiment and discover ways to optimize our operations.

Thanks for taking my questions, guys. John, I wanted to just ask, are you able to tell us the $150 million you have earmarked for exploration next year? This 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. It's a placeholder and we're working through. There's 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 work over 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 a wells or a volume offline that requires work over. We have a lot of sub pumps in Egypt and we've had some increase in the failures in a few areas and that number's ticked up. And Dave can get into some more color, but we've just got more barrels offline that we need to get to on the work over 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'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, but we're doing a broader look at that. And to put some numbers on John's comment, on base level of work over 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. So we've added a work over rig. We're doing some other things to start working that backlog down over time.

Hey guys 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 spillover into Egypt and have you been kind of in contact with the Egyptian government regarding them?

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 of Cairo into the Western desert. And if you go back in history, even over the Arab Spring, we have not had any shut-ins or major interruption in our operations. So I think the good news there is 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, so.

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 looking at that 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'll be being shot in Suriname in the where would be the development area, some other things. So it'll capture our exploration spend for next year and we'll come back with more details in February.

Hey, guys, thanks for taking the question. Really my question is around U.S. oil production, which looks like it's taken a pretty impressive step change. 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. Thanks.

It's essentially an ongoing program. We're seeing the advantages of our focused strategy. We've prioritized long laterals and secured the rig lines, allowing our teams the necessary time to execute. As a result, we have continued to drill long laterals and achieve positive outcomes. The timing of the completions plays a significant role. Regarding the addition of the sixth rig, it's primarily about reallocating capital from the North Sea to the Permian. We are optimistic about maintaining our strong performance. Looking at the fourth quarter, it's relatively flat compared to the third quarter, mostly because the third quarter exceeded expectations while the fourth quarter has not yet caught up. Overall, we are very satisfied with our execution level in the U.S.

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 Krabdagu 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 continue to deliver outstanding results in the Permian, where we've added a sixth rig which will add to the momentum as we enter 2024. We look forward to telling you more about the things in February and thank you for the call.