APA Corporation (NASDAQ:APA) Q3 2023 Earnings Call Transcript

APA Corporation (NASDAQ:APA) Q3 2023 Earnings Call Transcript November 2, 2023

Operator: Good day and thank you for standing by. Welcome to the APA Corporation’s Third Quarter 2023 Results Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. [Operator Instructions]. Please be advised that today’s conference is being recorded. I would now like to hand the conference over to first your speaker today, Gary Clark, Vice President of Investor Relations. Please go ahead.

Gary Clark: 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.

John Christmann: 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 work over projects over the last two quarters and a corresponding uptick in barrels offline. To address this, we have begun to increase our work over 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 6th 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.

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 asset. 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.

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Q&A Session

Operator: Thank you. At this time, we’ll conduct a question-and-answer session. [Operator Instructions]. And our first question comes from Doug Leggate with Bank of America. Doug, your line is open. Please go ahead.

Doug Leggate: 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.

John Christmann: 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.

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

John Christmann: I think it’s early on the —

Dave Pursell: 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 then we’ll — 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.

Doug Leggate: All right. Thank you. John, my follow-up is in Suriname; I managed to get a red eye to Total’s Analyst Day this year and asked Patrick a very specific question about timing. And I wanted to get your perspective on this. What — my understanding is that the 2028 schedule for first oil assumes a 42-month new build FPSO, but since that announcement, I understand that SBM has been selected with an early hull. In other words, a year earlier on that timeline 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.

John Christmann: 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.

Doug Leggate: Fair enough. Thanks, guys.

John Christmann: Thank you.

Operator: Standby for our next caller. And that is John Freeman with Raymond James. John, your line is open. Please go ahead.

John Freeman: 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 Christmann: 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.