APA Corporation (NASDAQ:APA) Q1 2024 Earnings Call Transcript May 2, 2024
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Operator: Good day and thank you for standing by. Welcome to the APA Corporation’s First Quarter 2024 Financial and Operational 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. Each person is limited to one question and one follow up. [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 for today, Gary Clark, Vice President of Investor Relations. Thank you.
Gary Clark: Good morning, and thank you for joining us on APA Corporation’s first quarter 2024 financial and operational results conference call. We will begin the call with an overview by CEO, John Christmann. Steve Riney, President and CFO, will then provide further color on our results and outlook. Also on the call and available to answer questions are Tracey Henderson, Executive Vice President of Exploration; and Clay Bretches, Executive Vice President of Operations. Our prepared remarks will be about 15 minutes in length, 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 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 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 on today’s call. A full disclaimer is located with the supplemental information on our website.
Please note that the first quarter 2024 results reflect APA Corp. only as the Callon acquisition was subsequently closed on April 1st. Accordingly, our full year 2024 guidance reflects first quarter APA results on a standalone basis, plus three quarters of APA and Callon combined. And with that, I will turn the call over to John.
John Christmann: Good morning, and thank you for joining us. On the call today, I will review our first quarter performance, discuss the compelling opportunities we are seeing after the closing of the Callon acquisition and review our activity plan and production expectations for the remainder of 2024. During the first quarter, upstream capital investment of $568 million was below guidance due primarily to the deferral of some planned facility leasehold and exploration spend. We continue to deliver excellent results in the Permian Basin with the first quarter marking our fifth consecutive quarter of meeting or exceeding U.S. oil production guidance. U.S. oil volumes were up an impressive 16% compared to the first quarter of 2023, and we expect organic growth to continue through the year as we integrate talent.
On the natural gas side, we chose to curtail a substantial amount of production at Alpine High, primarily in March in response to extreme Waha basis differentials. This dynamic has continued into the second quarter. In Egypt, gross production was in line with our expectations, while adjusted volumes were just shy of guidance due to the PSC impact of higher than planned oil prices. As discussed previously, we are in the process of rebalancing our drilling rig to workover rig ratio in Egypt to further optimize capital efficiency. In the first quarter, we averaged 17 drilling rigs and 21 workover rigs. While the workover rig count will remain flat, we will reduce the drilling rig count over the next three quarters, allowing workover rigs to be redirected.
The amount of oil production temporarily off-line and waiting on workover remained at around 12,000 barrels per day during the quarter, we expect to make progress on this as the drilling rig count comes down and freeze up workover resources. The challenges we experienced in the fourth quarter 2023 with faulty new electrical submersible pumps have now been fully remediated through vendor change out and design modifications. Turning to the North Sea. First quarter production was impacted by a decrease in average facility run time at Barrel in March. As a reminder, this type of downtime tends to occur more frequently and is less predictable when managing late-life assets like those we have in the North Sea. On the exploration front, we recently concluded our three-well Alaska exploration drilling program.
As a reminder, our 275,000 acre position lies on state lands, roughly 70 to 90 miles east of analogous industry discoveries. Our King Street #1 well confirmed a working petroleum system on our acreage, discovering oil in two separate zones. The other two wells, Sockeye #1 and Voodoo #1, were unable to reach their target objectives in the allotted seasonal time window due to a number of weather and operational delays. We are currently analyzing all of the data and we’ll come back later with more commentary on next steps in Alaska. Lastly, in Suriname, we are progressing the FEED study on our first development project, which we hope to FID before the end of the year. Turning now to the Callon acquisition, which closed on April 1, we are one month into the integration process and are making very good progress.
As anticipated, we are finding tremendous opportunities to reduce costs, improve efficiencies, leverage economies of scale and create value by applying our operational expertise and unconventional development workflows to the Callon acreage. Accordingly, we have increased our estimate of annual cost synergies by 50% from $150 million to $225 million. Steve will comment further on the timing and nature of these synergies in his remarks. The most exciting and compelling value capture opportunity we see with Callon still lies ahead. That will come from capital efficiency improvements which will enhance overall development economics and potentially expand the development inventory that form the basis of our transaction value. For the remainder of 2024, we will be revising most of Callon’s operational practices and workflows.
This includes everything from contracting and logistics, to well planning and design, drilling and completions, facility construction and many aspects of daily operations. At a high level, you will see wider well spacing, fewer discrete landing zones and larger fracture stimulations. Improvements in capital efficiency will manifest in fewer wells to deliver the same amount of incremental production volumes. While it will take some time to realize the full benefit of these changes, the implementation has already begun. In the meantime, we are modifying many aspects of Callon’s previous 2024 plan to capture as much near-term benefit as possible. Turning now to our activity plans and outlook for 2024, in yesterday’s release, we provided guidance for the second quarter and full year 2024, along with our expected oil production rates for the fourth quarter.
In the U.S., we have been running 11 rigs in the Permian since April 1. We expect to average approximately 10 for the remainder of this year as we actively manage changes to the combined rig fleet. You will see the rig count change as we drop some rigs when their term ends and pick up other rigs more suitable for the planned drilling program. Similarly, we will be making a number of adjustments to our combined frac schedule. In terms of oil volumes, we noted in our first quarter materials that we expect U.S. oil production in the fourth quarter to be around 152,000 barrels per day which represents an 11% growth rate from our second quarter guide of 137,000 barrels per day. Switching now to Egypt, in February, we commented that adjusted production would remain relatively flat in 2024.
Today, we anticipate adjusted production will decrease slightly as a function of the PSC impacts of higher-than-planned oil prices. And in the North Sea, production guidance for the full year is unchanged with an expected dip mostly in the third quarter as we conduct scheduled platform maintenance. In closing, we continue to manage our business with a clear and consistent strategy and deliver on our capital return commitments and financial objectives. The Callon acquisition is complete and the path to value creation is clear and well underway. Post Callon, our Permian Basin unconventional acreage footprint has increased by approximately 45% and our Permian Basin oil production has increased by more than 65%. The Permian Basin will represent an estimated 73% of APA’s total company adjusted production in the second quarter and will approximate 75% of our upstream capital this year.
Notably, our oil production weighting in the U.S. will increase to a projected 46% in the second quarter from 39% on a stand-alone basis in the first quarter. Finally, Steve will discuss our priorities around debt reduction, but I want to emphasize that our shareholder return framework has not changed, and we will continue to return at least 60% of our free cash flow via dividends and share repurchases. And with that, I will turn the call over to Steve Riney.
Steve Riney: Thank you, John. And good morning. For the first quarter, under generally accepted accounting principles, APA reported consolidated net income of $132 million or $0.44 per diluted common share. As usual, these results include items that are outside of core earnings, the most significant of which was a $52 million after-tax addition to the provision for costs associated with Gulf of Mexico abandonment liabilities. Excluding this and other smaller items, adjusted net income for the fourth quarter was $237 million or $0.78 per share. The resulting adjusted earnings for the quarter include some significant exploration dry hole expenses. Specifically, we took a $59 million charge for the two exploration wells in Alaska, which were unable to reach their targets.
Additionally, we wrote off the remaining $42 million we were carrying for the Bonboni exploration well in Suriname, which was drilled in 2021 and as we now have no active plans for further exploration in the Northern portion of Block 58. The total after-tax impact of these items on adjusted earnings was $88 million or $0.29 per share. In the first quarter, we returned $176 million through dividends and share repurchases. As John indicated, we remain committed to returning a minimum 60% of free cash flow to shareholders. We are also cognizant of the need to strengthen the balance sheet, and we are looking at non-core asset sales as a source of debt reduction, in addition to the 40% of free cash flow not designated for shareholder return. Our priorities for debt reduction will be the three-year term loan we used to refinance the Callon debt and the revolver.
Finally, we incurred roughly $20 million of costs associated with the Callon transaction in the first quarter and expect to incur an additional $90 million of such costs. The vast majority of which will be in the second quarter for professional services, departing Callon employees and other closing costs. Now let me turn to progress on the Callon integration. One month into the process, we are on track to realize more cost savings than originally projected. As John noted, we have revised our annual synergies from $150 million up to $225 million. Recall, we put expected synergies into three categories: overhead, cost of capital and operational. Annual overhead synergies have been revised up from $55 million to $70 million. This is moving quickly, and we will capture approximately 75% of this on a run rate basis by the end of the second quarter.
We expect by year-end, nearly all of these synergies will be realized and our go-forward G&A run rate will be around $110 million per quarter. Expected annual cost of capital synergies are unchanged at $40 million. The initial refinancing of the Callon debt realized a portion of these synergies and they will be fully realized when the debt is termed out or paid off. We are seeing the greatest amount of opportunity in operational synergies. Our original estimate for this category was $55 million, which we have revised upward $215 million. We are making extremely good progress in this area, some of the more impactful items that we are working on include recontracting of frac services in rig high-grading artificial lift optimization, which will lower LOE and reduce downtime, supply chain synergies for casing and tubing, sand, chemicals and other items, compression fleet optimization and economies of scale and well design improvements that eliminate extra casing strings and reduced drilling days.
Further down the road, we see additional potential in areas like gas marketing and transportation and water handling, disposal and recycling. To reiterate, these cost synergy estimates do not include capital productivity effects associated with improvements in well type curves and economics through well spacing, landing zone optimization and frac size. Turning to our 2024 outlook. John has already discussed our activity plans and production guidance. So I will just touch on a few other items of note. Other than reflecting the Callon acquisition and our outlook, the most material change to guidance is associated with gas pricing in the Permian and its impact on expected near-term production and third-party gas marketing activities. As most of you are aware, Waha experienced severe basis differentials in March and April, we expect this will continue through much of May.
As a result, we have continued to curtail gas into the second quarter and our 2Q guidance now reflects an estimated impact on the quarter of 50 million cubic feet per day of gas and 5,000 barrels per day of NGLs related to the weakness at Waha Hub. Our income from third-party oil and gas purchased and sold, including the Cheniere gas supply contract is expected to be around $230 million for the full year, which is up significantly from our original guidance of $100 million. You will also see that we have removed DD&A from our guidance at this time. We are still working on the Callon purchase price allocation and aligning our reserve booking practices. We will reinstate D&A guidance with the second quarter results. Finally, as a reminder, APA will be subject to the U.S. alternative minimum tax starting in 2024.
We incurred no AMT in the first quarter and do not expect to in the second quarter. Based on current strip prices, we will likely incur these costs in the second half of the year. And with that, I will turn the call over to the operator for Q&A.
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