Talos Energy Inc. (NYSE:TALO) Q4 2022 Earnings Call Transcript

Talos Energy Inc. (NYSE:TALO) Q4 2022 Earnings Call Transcript March 1, 2023

Operator: Good day, and welcome to the Talos Energy Fourth Quarter and Full Year 2022 Earnings Conference Call. All participants will be in listen-only mode. Please note this event is being recorded. I would now like to turn the conference over to Sergio Maiworm, Vice President of Finance, Investor Relations and Treasurer. Please go ahead.

Sergio Maiworm: Thank you, operator. Good morning, everyone, and welcome to our fourth quarter and full-year 2022 earnings conference call. Joining me today to discuss our results are Tim Duncan, President and Chief Executive Officer; Shane Young, Executive Vice President and Chief Financial Officer; and Robin Fielder, Executive Vice President, Low Carbon Strategy and Chief Sustainability Officer. Before we get started, I’d like to take this opportunity to remind you that our remarks today will include forward-looking statements. Actual results may differ materially from those contemplated by these forward-looking statements. Factors that could cause these results to differ materially are set forth in yesterday’s press release and in our Form 10-K for the period ending December 31st, 2022 filed with the SEC yesterday.

Any forward-looking statements that we make on this call are based on assumptions as of today and we undertake no obligation to update these statements as a result of new information or future events. During this call, we may present both GAAP and non-GAAP financial measures. A reconciliation of GAAP to non-GAAP measures was included in yesterday’s press release, which was filed with the SEC and which is also available on our website at talosenergy.com. And now I’d like to turn the call over to Tim.

Tim Duncan: Thank you, Sergio. Good morning and thanks for joining our call. 2022 was another transformative year for Talos with key milestones across our Upstream and CCS businesses. Our team has advanced the catalysts to drive future value creation. These accomplishments have only been possible with our employee’s hard work and focus. So, thank you first and foremost to our Talos’ employees for a job well done over the past year. In 2022, we attained record-setting financial performance, completed a major M&A addition to our business with the EnVen acquisition, and advanced our carbon capture and sequestration business from EnVen to one of the largest carbon storage portfolios in the United States. We meaningfully strengthened our credit statistics and liquidity profile throughout the year with free cash flow generation and today our credit position is the best in our history.

These strategic accomplishments were achieved while maintaining our high safety and environmental performance standards. Before addressing the fourth quarter and full year 2022 projects and results in detail, I want to take a moment to address four very important topics. First, the value of our year-end reserves. Second, our 2023 guidance and long-term outlook that Shane will discuss in more detail later. Third, our capital allocation framework and how we intend to balance investments and our highly cash flow generative upstream business, and our high growth CCS business while also providing a path towards returning capital to shareholders. And fourth, the solid results of our ongoing drilling program. Starting with the value of our year-end reserves.

On a pro forma basis for the EnVen transaction, we ended 2022 with a larger, more diverse, and more liquid-weighted reserve base. Talos proved reserves are 190 million barrels of oil equivalent, which is approximately 70% oil. The PV-10 of our proved reserves is approximately $7.2 billion at SEC prices, assuming a flat $75 per barrel price deck, which is more in line with today’s prices. The PV-10 of our proved reserves is $4.8 billion. The PV10 of Talos’s proven developed producing reserve base or PDP is $3.5 billion still at $75 per barrel. The PV-10 of our current production alone is approximately 5% greater than our current enterprise value and 45% higher than our current market capitalization. I bring that up because I believe investors are able to get extraordinary option value.

for all the investments we are making in the business outside our current production. This is also why we are extremely focused on bringing the value of key catalysts forward from our ongoing drilling program to reaching FID and Zama to continuing to be an active acquirer of assets in the Gulf of Mexico and substantially growing our CCS business. The runway for upside in our stock is tremendous. Turning to our 2023 guidance, we provided yesterday in the earnings release Talos’s estimating production between 72,000 and 76,000 barrels of oil equivalent per day for the year. That expectation is based on our very conscious decision that we’ve made to focus the business on 2023 free cash flow generation and long-term shareholder value creation. With that in mind, we decided to remove the gas-weighted Lisbon prospect from our 2023 drilling calendar despite its near-term potential gross production impact of approximately 8,000 to 10,000 barrels of oil equivalent per day.

Instead, we will preserve Lisbon in inventory for a subsequent year, when the economics of gas-weighted projects are more attractive. That decision was also made as we will incur additional success-based development capital in 2023 to accelerate our recent Venice and Lime Rock discoveries to first production in early 2024. We knew this decision could cause some short-term volatility to our 2023 production, but we firmly believe this is the right decision to position Talos for long-term value creation for our shareholders. Longer-term Talos is healthier than it’s ever been, because of our recent successes in our development and exploitation drilling program, most of which will come online throughout 2023 and 2024, and our bullish outlook on several of the projects we’re planning to drill this year.

We expect our production will grow 20% to 25% between now and 2026. That’s a compounded annual growth rate of approximately 6% to 8% per year. We also expect to generate a cumulative free cash flow of $2 billion to $2.3 billion during the same period between 2023 and 2026 at a flat $75 per barrel price forecast. That is a very healthy business and one that we’re really excited about. Concerning our capital allocation framework, our priority continues to be free cash flow generation and paying down debt. Over the last two years, we have paid back over $480 million in debt bringing our leverage metric near its lowest level in our history. In the last 12 months alone, we have transferred firm value to shareholders by repaying $4.77 per share worth of debt but we think there’s still a bit more we need to do in addition to leverage metrics we are also paying attention to the overall quantum of debt on our balance sheet.

As a catalyst-rich company, we fundamentally believe in the equity growth projects that we have in our portfolio. We intend to continue to invest in those projects, whether it’s in our oil and gas business or our CCS business because we believe they will create substantial value to our shareholders. After we re-prioritize continued debt reduction and continue to appropriately reinvest in our business, we are also prepared to return incremental free cash flow generation to our shareholders, primarily through opportunistic share repurchases subject to further approvals of our Board of Directors. We expect to be in a position to accelerate this return of capital once we meet our debt reduction goals. In addition, Talos will consider participating in share repurchases in connection with any potential private equity shareholder monetization event that could occur over the next several years subject to approval by our Board.

We believe this could help alleviate the technical overhang in our stock and significantly benefit Talos’ broader shareholder base. Finally, looking at our ongoing drilling program and on a pro forma basis, including the recently acquired EnVen assets, we have drilled six successful development and exploitation wells. We look forward to the positive impact those wells will provide throughout 2023 and into 2024. In Puma West, we commenced drilling of our appraisal well in late 2022, which we subsequently followed up with a sidetrack of the appraisal wellbore. The project has had mixed results to date, as the appraisal wells did encounter hydrocarbons in multiple sands. However, our preliminary analysis suggests that additional hydrocarbons from a subsequent well, where a sidetrack well would be necessary to move forward with a full-scale development.

With that said, we have temporarily suspended the current well bore, which provides us the flexibility to drill a future sidetrack, we are actively working to incorporate the data from the appraisal wells to determine the best path forward. Our teams are studying the data now and will continue to provide important updates as available. For the remainder of my prepared remarks. I’ll quickly address our financial results for the full year, highlight our drilling program, comment on our value accretive transaction, discuss our advancements in CCS, and conclude with a few remarks about our safety and environmental performance. For the full year of 2022, our production was approximately 59,500 BOE per day weighted at 67% oil and 75% liquids. We achieved adjusted EBITDA of more than $840 million.

We generated a record $261 million of adjusted free cash flow, which allowed us to end the year with the highest liquidity and near the lowest leverage in our company’s history. Shane will provide more details on this shortly. Regarding our previously mentioned drilling successes. The second half of 2022 and early 2023 have been very busy with drilling projects across the Gulf. I’m very proud of our team for our success thus far totaling six successful projects to date. Our previously announced Lime Rock and Venice discoveries located near Talos’s 100% owned and operated Ram Powell Platform in Mississippi Canyon were both successful. Those projects could deliver a combined 15,000 barrels to 20,000 barrels of oil equivalent per day gross once they come online in the first quarter of 2024 contributing to the highest gross production rate achieved in Ram Powell facility in over 15 years, which is exactly what our strategy of infrastructure-led drilling is expected to achieve.

The existing infrastructure grants us the ability to flow our newly discovered barrels in the subsea environment, which has a much lower emissions footprint than other oil-producing basins. This highlights why the deepwater Gulf of Mexico continues to be a leader in low-emissions barrels. The Talos-operated Mount Hunter prospect in the Pompano field was successful and we expect this project to deliver gross production rates of 2,000 barrels to 4,000 barrels of oil equivalent per day with first production expected by the second quarter of 2023. EnVen’s Lobster platform rig program also generated solid results towards the end of last year discovering pay in multiple field horizons and achieving fresh production in the first quarter of this year.

Our non-operated projects are also achieving a high degree of success with recent discoveries from the Gunflint Number One sidetrack and The Spruance West wells. The rig on our open water program has moved to a recompletion project at our bullet discovery. After that, the rig will move to the Rigolets prospect, our third exploitation target in the open water rig program, if successful Rigolets would flow via subsea tie back to Talos’s Pompano platform. We could see gross production rates of about 8,000 barrels to 12,000 barrels of oil equivalent per day Rigolets with first oil reached by the second half of 2024. Talos owns a 60% working interest in this project. Following Rigolets, we plan to drill the Sunspear prospect. This is a great prospect from the EnVen portfolio and we are excited to drill it in the second half of the year.

If successful, we expect to tie it back to the Prince platform that we acquired in the EnVen transaction. Gross production rates are expected to be between 8,000 barrels to 10,000 barrels of oil equivalent per day. We own a 48% working interest in this project. Another project we are very excited about is Pancheron. Pancheron is a high-impact project, we own with Oxy following the completion of a 46,000-acre continuous track, we were able to combine with them. Oxy is the operator of the project and we expect to spud the well in the first half of 2023. Talos owns a 30% working interest. Overall, we are excited about the potential material production growth and cash flow in 2024, and beyond that these discoveries in our drill campaign will add.

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We pride ourselves on utilizing our core technical and operational skills to optimize projects across our portfolio while leveraging infrastructure we own or acquire through active business development. That strategy has led to successes at Lime Rock, Venice, and Mount Hunter just in the last quarter, with Rigolets, Sunspear, and others on the immediate horizon. This is a strategy that is generating solid results, which leads me to our EnVen acquisition. As previously announced, we closed the EnVen transaction in mid-February. The transaction expands our Gulf of Mexico operations with high-margin oil-weighted assets in ample infrastructure. It’s accretive to Talos’s shareholders and further improves our outstanding credit position. With the acquisition, Talos is better positioned to accelerate organic value-creating activities through both our upstream and CCS businesses as well as any subsequent M&A and business development activities.

The integration of our companies is on track and we will work to realize the valuable synergies that we expect to generate for the combination. We will continue to update the market on this integration and our synergy realizations later this year. Turning to our CCS business. I want to first reiterate the incredible progress the team made in 2022. This included securing multiple major sequestration sites, bringing in key partners across the portfolio in building out a team that will drive those projects and more to maturation. I’m incredibly proud of our early leadership position in our advancements in the business along the U.S. Gulf Coast. There is an extraordinary level of enthusiasm about the promise of what CCS can become after the expansion of the 45Q tax incentive structure in 2022.

We have often said that if CCS is going to work anywhere in the world, it has to work in the Gulf Coast of the United States. Here we have the combination of the right economic incentives, a large concentrated industrial emissions market, existing midstream infrastructure and the superb geology required to permanently sequester and monitor the injected CO2. And to continue to complement our already strong acreage position across our portfolio, yesterday, we announced the Talos’ elected to participate alongside Chevron and an onshore CO2 sequestration leasehold in Southeast Texas that combined with our Bayou Bend CCS project will give us a gross storage capacity of more than one billion tonnes of CO2 in this project alone. That will allow us to be very competitive for emissions in the Houston Ship Channel as well as the Beaumont Port Arthur industrial corridor.

Additionally earlier this month, our Coastal Bend carbon management partnership which includes Talos, Howard Energy Partners. the Port of Corpus Christi Authority and the Texas A&M University system were selected for a $9 million grant from the U.S. Department of Energy’s Carbon Storage Assurance Facility Enterprise, also known as CarbonSAFE. Under the terms of the award, grant funding will directly reimburse a majority of the upcoming technical and economic feasibility costs including a stratigraphic evaluation well, FEED studies, and other key project work streams. The grant award is subject to final negotiation with the Department of Energy. Additionally, Talos and Howard teams finalized in February definitive documents for the 13,000-acre lease with the Port of Corpus Christi team securing the pore space for that regional project with additional potential opportunities to expand in the future.

For TLCS, our 2023 goals are straightforward grow our existing portfolio and increased storage capacity in existing project areas, expand partnerships in existing project areas, progress the permitting and front-end engineering design work streams, advance and execute commercial contracts and develop additional point source projects. We look forward to providing more exciting updates throughout the year as we continue to grow the business. Our record-setting trend continued into categories of safety and environmental responsibility. 2022 was another historic year for reducing our lost time incident rates and greenhouse gas emissions intensity. Over the years Talos’s proactive and continuous evolving approach to HSE management has improved our incident rates resulting in a 25% reduction from our previous year’s TRIR.

In 2022, we reduced our Scope 1 GHG emissions intensity by 30% from the company’s 2018 baseline year, achieving the company’s initial goal three years sooner on a pro forma basis, including the EnVen assets. With that, I’ll turn the call over to Shane to address our financial details for the fourth quarter and the full year as well as an overview of our 2023 operational and financial guidance.

Shane Young: Thank you, Tim, and good morning, everyone. Today, I’ll focus my remarks on four key areas. First, the highlights of our financial performance for the fourth quarter and full year 2022. Next, the strength of our pro forma balance sheet. Third, I will cover our 2023 guidance. Finally, I will discuss our capital allocation priorities for our adjusted free cash flow and summarize our financial goals before turning the call back to Tim for his closing remarks. During the fourth quarter of 2022, our production volumes averaged 56.6000 barrels equivalent per day and we’re highly liquids weighted at 76%. This production volume was just above the midpoint of our fourth quarter guidance and was inclusive of the previously announced impact of downtime associated with loop currents in October and other maintenance and timing updates.

Realized prices before hedging during the fourth quarter were $80.87 per barrel of oil. NGLs were at 30% of our realized oil price and $6.10 per 1,000 cubic feet of natural gas. This resulted in revenues of $342 million for the quarter. Net income for the fourth quarter was $2.8 million or $0.3 per diluted share. Adjusted net income was approximately $17 million or $0.20 per diluted share. We generated adjusted EBITDA of $185 million during the quarter. On a per barrel of oil equivalent basis, this translated to an adjusted EBITDA margin of about $36. Adjusted EBITDA, excluding realized hedge losses, was $242 million and a margin of approximately $47 per barrel of oil equivalent. This represents 65% and 71% margins, respectively. Capital expenditures and plugging and abandonment were approximately $156 million for the quarter and were below our previously provided guidance range.

This is the result of timing shifts in our capital program from the fourth quarter into the 2023 program. Turning to the full-year 2022, Talos generated production of 59.5000 barrels equivalent per day and again was highly liquid weighted at 75%. Realized prices for our production during the year were $93.75 per barrel of oil, NGLs averaged 35% of our realized oil price, and $7.6 per thousand cubic feet of natural gas. This resulted in full-year revenues of approximately $1.7 billion. Net income for the full year was about $382 million or $4.56 per diluted share. Adjusted net income was approximately $244 million or $2.92 per diluted share. We generated corporate adjusted EBITDA of approximately $842 million for the full year, inclusive of approximately $13 million and $5 million of expenses associated with our investments in CCS and unallocated overhead respectively, which means Talos Upstream business generated approximately $860 million of adjusted EBITDA in 2022.

You will note that in our 10-K filed last night, we have begun to break out selected items including adjusted EBITDA by reportable segment. These strong results were supported by the team’s continued vigorous focus on cost controls throughout the year as both LOE and G&A expenses finished the year within our original 2022 guidance. Capital expenditures of approximately $456 million for the year were at the low end of our guidance range and equated to a 54% reinvestment rate for the year. As a result, Talos generated adjusted free cash flow of $261 million before changes in working capital. In 2022, we use our adjusted free cash flow to repay borrowings under the company’s credit facility as well as the repurchase of a portion of our second lien notes for a total debt reduction of $393 million or approximately $4.77 per share in total debt reduction for the year.

Turning to our balance sheet. As of December 31st, 2022, the total debt stood at approximately $639 million and there were no outstanding borrowings on our RBL. Our liquidity of $847 million was our highest ever while leverage was near our lowest in the company’s history. Upon closing the EnVen acquisition on February 13th, our borrowing base under our RBL increased by 36% to $1.5 billion and our bank commitments increased by 20% to $965 million. In addition, the maturity date of the credit facility was extended to March 2027 from November 2024 among other favorable changes. Maintaining low leverage and high liquidity has been a longstanding core financial principle for Talos. With the close of the EnVen transaction, we assume $258 million of their notes and used a $130 million draw on our RBL along with cash at EnVen to fund the cash consideration and other closing costs.

We intend to continue to focus on deleveraging and repayment of outstanding debt in 2023, which we’ll discuss in more detail as part of our capital allocation guidance. Additionally, as of April 15th both sets of notes will be callable and we will monitor the attractiveness of market conditions over the balance of 2023 as we consider potential refinancing opportunities for one or both of the notes. Now let’s turn to our operational and financial guidance for 2023. Starting with production. We expect the full year to average between 72,000 and 76,000 barrels of oil equivalent per day, of which approximately 80% will be liquids and this represents an increase of approximately 21% to 28% from our 2022 production levels. This is inclusive of the impact of approximately 10.5 months of the production from the EnVen acquisition.

Also factored into our production expectations and capital allocation plans for the year is the deferral of our gas-weighted Lisbon project originally planned to be drilled in online in mid-2023 with an expected average daily rate contribution of 8,000 barrels to 10,000 barrels of oil equivalent per day gross. We will instead keep this opportunity in our inventory until natural gas prices are more favorable. However, tabling this prospect gives us increased flexibility to generate meaningful 2023 adjusted free cash flow while continuing to focus capital on our most value-accretive opportunities in the portfolio. For instance, this would include capital spending to complete and tie back the Lime Rock and Venice discoveries as well as continuing to invest in our higher impact drilling projects such as Rigolets and our non-operated Pancheron that would boost start production beyond 2023.

For the year, we expect the first quarter to be the lightest production quarter with a 50% contribution from the EnVen assets. The second quarter is expected to be relatively clean with the third quarter and fourth quarters reflecting weather-related risking, planned maintenance, and the removal of the platform rig at our Pompano facility. We expect our cash operating costs and general administrative expenses for the full year of 2023 to be between $410 million to $430 million and between $90 million and $95 million respectively as we reflect a partial year capture of anticipated synergy realizations from the EnVen acquisition. However, we do anticipate hitting a full initial synergy realization run rate in late 2023. Interest expense is expected to be between $155 million to $165 million, including cash interest expense on our two second lien notes and our RBL, the interest component of the HP-1 finance lease, as well as non-cash financing expenses and surety bond premiums.

Upstream capital expenditures for the year are expected to be $650 million to $675 million while plugging and abandonment expenses are expected to be $75 million to $85 million. Total CCS investments are expected to be an additional $70 million to $90 million and will be a mix of capital, G&A, and other income statement expenses. For the year, we anticipate the first quarter will be the heaviest capital quarter with the balance of the capital spread relatively evenly over the final three quarters. This year’s capital program is an exciting one for Talos as we continue our successful open water rig program from 2022 into 2023. Tim briefly addressed this earlier in his remarks, but in yesterday’s earnings press release, we outlined some key measures of how this 2023 guidance unfolds in 2024 and beyond.

We expect to maintain our longstanding 3% to 5% organic growth rate. So we expect this rate to increase to 6% to 8% from 2023 through 2026 while simultaneously reducing our capital reinvestment rate from implied 2023 guidance levels. From 2023 through 2026, we anticipate adjusted free cash flows before working capital and cash taxes of between $1.7 billion to $2 billion at the current strip or $2 billion to $2.5 billion at $75 and $350 flat price decks. Those figures amount to over two times our total debt post EnVen closing in anywhere from 75% to 110% of Talos’ current market capitalization. Our 2023 plan is an important step in achieving those long-term results, as we invest in bringing new resources to production while exposing Talos to additional prospects that contribute to that growth rate despite not providing 2023 production volumes.

Importantly, yesterday we also outlined a capital allocation framework that we intend to deploy beginning in 2023. First, we intend to focus on reducing leverage by at least $100 million this year, most likely through pay down of our RBL. Having taken on the EnVen notes and drawing approximately $130 million as part of the EnVen closing, we are prioritizing debt reduction with initial adjusted free cash flow. Second, we intend to be opportunistic with our CCS business and we’ll deploy capital accordingly to best position Talos Low Carbon Solutions for long-term success in line with project milestones and accretive expansion opportunities. Finally, incremental adjusted free cash flow beyond these projects will be allocated towards a blend of debt reduction and shareholder returns.

We will further define this blend at the appropriate time. Separate from this framework and subject to Board approval at that time, we may look to mitigate outsized selling impacts and capitalize on the strong long-term value proposition in our shares through participating and potential secondary offerings by private equity shareholders. In closing, we fundamentally believe that Talos’ opportunity sets are unique among U.S. energy companies in many ways. To advance our differentiated position and our key catalysts, our capital objectives for 2023 are clear. Remain focused on adjusted free cash flow generation, invest in growing our resource base and production footprint, invest in our growing Gulf Coast leading CCS portfolio, and continue to strengthen our healthy credit position.

With that, I’ll now hand the call back over to Tim.

Tim Duncan: Thanks, Shane. 2022 was a highly successful and busy year. 2023 is going to be a foundational year for our future growth plans across both upstream and CCS businesses and we believe we’re well-positioned to capitalize on our rich portfolio of opportunities. With that operator, we’ll open the line for Q&A.

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Q&A Session

Operator: Our first question comes from Nate Pendleton with Stifel. Please go ahead.

Nate Pendleton: Good morning and thanks for taking my questions.

TimDuncan: Hi, Nate.

Nate Pendleton: My first question now that the EnVen acquisition is closed. Do you expect a change in your M&A strategy going forward, and can you characterize the M&A market in the Gulf?

TimDuncan: Yes. Hey, Nate. Thanks for the question. I don’t think it changes. I mean we’re always in the market, we’re always trying to find the right deals to hit the right characteristics. Do we understand the assets? Does that overlay with what we’re trying to do from a technical and operational standpoint? Do we see the upside potential ultimately doesn’t make us a more sustainable business and accretive to our shareholders? Sometimes that can happen relatively quickly between the ILX deal and the EnVen deal we had a period of over two years. And so I don’t think it changes, who we are and what we’re trying to do, which is be the logical aggregator for the right assets in the Gulf of Mexico, but you always have bid-ask spreads, you always have sources and uses questions, and so we just have to be thoughtful on how we approach the market.

Look, I think the majors some assets, we’re starting to come to the market, whether that it gets accelerated this year. It’s hard to tell. Obviously, these owners of assets can wait another year but does the market. So, we just have to be active. We have to be disciplined and we have to just keep checking the right boxes.

Nate Pendleton: Thanks. And regarding the addition of storage capacity in Southeast Texas near Bayou Bend, can you speak to your views on how important high-quality poor space will be in the future and the competition you’re seeing in the market today?

TimDuncan: Look, I’ll start and then Robin can add a couple of comments. I mean, I think our general premise in this entire thing that I did talk about in my prepared remarks was for this to work, you just have to have that combination of an emitting market. So an industrial market where those industrial partners are focused on reducing their emissions and then their transportation segment, and then the right storage infrastructure that has the right geology that can really be attractive ultimately to that customer, and that’s the basis. And Robin can talk about some of the highlights of what we’re trying to do in that portfolio.

Robin Fielder: Yes. We’re excited over the last couple of years, we’ve been building out the leasehold position. Since the middle of last year we basically nearly doubled the amount of CO2 storage, we’re approaching 1.6 billion metric tons across our Texas and Louisiana Gulf Coast portfolio. And as Tim said, it’s exciting for us because it’s really we’ve got some of the best geology in the world next to these industrial corridors. We’ve got some strategic partners that are going to help us advance these projects with key footprints or skill sets in this space. And so now it’s really talking with those industrial partners and collaborating with them on their sustainability goals and getting these underlying emissions into our storage sites.

TimDuncan: Nate what we talked about in the release with respect to Chevron and participating in their acreage expansion. I think that also underscores again what we bring to the table, we think is a depth of understanding around the geology. Obviously, Chevron has that as well but we also didn’t get to pair that with their own ambition and I think that’s meaningful for us and it speaks to, I think what we’ve done as a team to build out the right portfolio. So we’re just super excited where that’s going and just those 2023 priorities of continuing to find the right storage infrastructure in our core areas and continuing to enhance these partnerships is only going to deliver the long-term value of what we’re trying to build here.

Nate Pendleton: Thanks. And if I could sneak in one quick follow-up regarding the CCS investment guidance for 2023. Can you speak to how much of that is related to pore space acquisitions and how you expect that overall CCS investment to trend beyond 2023?

Robin Fielder: I mean the leasehold acquisition and even some of our annual renewals is a portion of that, but we are planning to be drilling some of the strat wells. So this year will we will be collecting data including some addition of some seismic data, drilling the stratigraphic test wells, we will collect both logging-in core data. All of this is to supplement what we want to hope to be a very robust EPA Class 6 permit application. I will also be engaging in some pre-FEED and front-end engineering design that Tim mentioned in his prepared remarks. So, it’s really all these activities that help advance the projects, help develop the storage sites, get us set up for these permits that gives our customer base, the comfort that these projects are going to make it and that they’re going to be highly successful in these regions.

Nate Pendleton: Great. Thanks for taking my questions.

TimDuncan: You got it.

Operator: Our next question comes from Subash Chandra with Benchmark Company. Please go ahead.

Subash Chandra: Yes. Hi, Tim. Hi, everybody. Maybe just a follow-up. Good morning. On CCS, broadly speaking, how would you handicap 2023 if you get to sort of favor one project versus another or a major contract that you might see that progress? And then secondly, I guess on Chevron specifically, is there a midstream partner in the works there? Do you need one there? Then I have a follow-up. Thanks.

Robin Fielder: Hi, I’ll jump on that Subash, thanks for the question. Broadly, I’ll say that we’re actively participating in RFPs with industrial partners across our portfolio, also and some one-off negotiations on some term sheets on I’ll say both brownfield emissions and potential greenfield new investments. So that’s very exciting for us. I think as you just kind of look at these industrial regions. One of the reasons we’re so excited about this additional leasehold in East Texas is it’s ability to address to industrial corridors not only the Beaumont Port Arthur region, but now also the Eastern Houston Ship Channel. So we think there’s going to be a lot of good progress made across this portfolio and so that’s why we’re excited about that.

I’m sure with Chevron. They certainly have capabilities all across the value chain. They’ve got Chevron pipeline and power. One of my predecessor companies, Noble Midstream Partners got folded into that entity. So we haven’t decided yet. They certainly can take that on. We can work with third-party midstream companies that are all thinking about how they’re going to position themselves to move CO2 for the future.

TimDuncan: Yes, one way to think about this Subash at least as I think about it, you look at the core areas that we’ve been focusing on the Corpus Christi area, the Southeast Texas, which is kind of the Ship Channel Beaumont, Port Arthur and then around the river in Louisiana and you have to ask yourself, is there an inevitability that this market can make. Is there an emission source? Is there a will? And then from there, you asked the question is where they’re going to put it in here, you’re going to partner with and we’ve tried to first show that inevitability by making sure people understand the breadth of these markets and then now you look at the accumulation of storage infrastructure. And so your question is a good one on the midstream.

Certainly, we’re trying to take that off the table with the different partnerships we have in different areas, and then, of course, Chevron just themselves can play a part. So we’re checking the boxes where you can kind of look out three years from now, five years from now, say, look, I can see how this works. And so we’re proud of that and we just got to keep pushing and keep advancing and Robin’s team is doing that.

Subash Chandra: Okay. Good color. Thanks. And then the second is on Puma West, I guess. What do you think now of timing of a determination or proceed and when you — when you talk a full development or is there a distinction here between a tie back or standalone, or are we still sort of do we drill more or don’t we.

TimDuncan: Yes, no, I think it’s making sure you have everything you need to make that kind of commercial decision. I mean if you think about the Mad Dog field. It’s just an enormous resource and what we’re always trying to do in Puma West was take the characteristics of that field and see if they were present to the west and the characteristics, you’re looking for is doesn’t have the right geology doesn’t have those sands those Middle Miocene sandstones. Are they present to the west? Do you have a source in charge? Is that present and do you have the full connectivity? Do you think you have to have to go ahead and make a commercial decision? I think we’ve checked a couple of those boxes but not all the boxes, and we have we wouldn’t talk about multiple pays obviously there’s charge or we wouldn’t say there were hydrocarbons but we want to see the connectivity and the things you need to make that commercial decision and look, I think the view of the partnership is it probably needs another wellbore to really understand that.

And so it’s not full development this was never intended to be something where people are trying to spend $1.5 million into a full development, there’s ample infrastructure in the area. These are still very expensive projects and you want to make sure you get them, right, and it’s going to require another what to do that. We have time to make that decision. You have another year, anytime you drill a well like we did to kind of think about your next steps and I think the partnership is going to absorb the data and think about what the right next moves are.

Subash Chandra: Okay, got it. So for clarity there. So there’s nothing here in the next three months or six months that you would think that’s probably more about the study. And maybe if any ’24 events.

TimDuncan: No. That’s exact.

Subash Chandra: Great, thank you.

Operator: Our next question comes from Jeff Robertson with Water Tower Research. Please go ahead.

Jeff Robertson: Thanks, Tim. On the heels of the EnVen acquisition and the amount of free cash flow that you all laid out between now and 2026, does that change at all how you think about allocating capital in assessing risk across the upstream portfolio in the Gulf?

TimDuncan: Well, I’ll start there and Shane can speak some other comments, one thing to keep in mind maybe not be fully understood, and what we’re talking about in our prepared remarks, is we did have six straight exploitation and development well successes and what happens there, if you can think about Lime Rock and Venice and what we talked about earlier you don’t assume all those are going to work, maybe assume two out of three of those are going to work. When you have six in a row, you have to unrisk a lot of capital and so we have capital in the system that on a risk basis, you may not anticipate they didn’t deliver those unrisk results in the second half of this year and going into 2024. The point being we’re taking some risk off knowing that production is coming, and so I think that’s very positive.

That’s why we’re very bullish about 2024 and ’25 and ’26. It’s also why we don’t have to add another project specifically in 2023 that was gas weighted put that later into our portfolio when the market is more constructive. I still think though, we want to continue to have a portion of our capital allocated towards things that can be really high impact, which is what Puma West can be, which is what Pancheron can be. We don’t want to overweight our capital program with that, but it always makes sense when you’re an operator in the Gulf of Mexico to expose yourself to those opportunities. So very bullish about the successes we had and the impact they’re going to have, still want to always make sure we have a blended portfolio of the things we’re doing going forward.

Shane Young: Yes, Jeff, I would just say I think the advantage of that and having sort of the size and scale and the ability to deploy capital program that is diverse and has different risk characteristics is we’re trying to develop a bit of a conveyor belt. So as we get to the end of this year, beginning of next year we got Lime Rock, we got a Venice coming online that’s going to add fresh production to the mix, we’re drilling a rig lead in Pancheron this year that would hopefully to the extent we have success, begin to come on kind of in the next stage beyond that. I think each and every year we’d like to be in a position to expose the shareholders to that kind of opportunity.

Sergio Maiworm: I think what changes brought up to as we always have to understand is our cycle times are different than what you see sometimes in the onshore unconventional. What might take three, four months to bring the well online and the onshore can take 12 to 18 to 24 months and so that’s why we wanted to make sure we were reiterating a broader compounded annual growth rate on the production side, even if again some years you’re taking a step back to move forward. It’s just the nature of the cycles of how we bring on subsea wells.

Jeff Robertson: Okay. Along those lines Tim, the EnVen assets also added a lot of infrastructure that has a lot of unused currently unused capacity, right? How do you assess the opportunities to either add third-party volumes through those if there’s a third-party activity in the area? And as you all know, look at those assets to start to try to define or develop prospects. Is that more of a tough 2024, ’25, ’26 event?

TimDuncan: No, actually I don’t think so. I would tell you, just from a business development standpoint. I think the pace has picked up as other operators in the area, know that we’re controlling those assets and we’re looking at other opportunities, and so we hit very hard as soon as we close. For example, do we launch some additional reprocessing projects around those platforms, which is exactly what we did around Ram Powell that led to Venice and Lime Rock discovery? So the approach we took to the strategy of our infrastructure in the past is exactly the approach we’ll take these and look they had some inventory going in, that we’re trying to firm up as well. So we’re extremely bullish on it, and again it’s consistent with the strategy and what we talked about this.

It creates a lower carbon emitting barrel, we’re using the infrastructure, we’re focused on subsea tiebacks, I would expect Prince, Lobster you’re going to see hopefully Brutus/Glider, you’re going to see these assets be a part of the discussion on where we’re drilling locations in the next two to three years. I’m fully confident of that.

Jeff Robertson: One question, if I can on the CCS? Does the acreage expansion at Beaumont, Port Arthur, and these 1 billion tons of storage capacity? Is that an important aspect both in terms of cost and being able to show potential emitters that you’ve got the sink to take their CO2? Does that help advance some of those discussions with emitter, either Tim or Robin?

Robin Fielder: Absolutely. It’s great to have built-in backup storage sites that is apt for our customer base to show that we’ve got multiple places in our portfolio where we can take the CO2 and certainly having it situated close to those two markets is very important, that’s the low-cost nature that we’re trying to be competitive here.

TimDuncan: Yes, I think Robin has talked about in the past, operational assurance as a criteria for the customer base. And so when you can show you have redundancy when you can show you have multiple options that turn, that take some risk off the table for the emitter as well. And so, yes, it’s important that we have a leadership position both in the strength of our partnership and the size and capacity of our storage asset when we’re talking to the broader marketplace in these big hub areas.

Jeff Robertson: Thank you.

TimDuncan: Thanks.

Robin Fielder: Thanks.

Operator: Our next question comes from Leo Mariani with MKM Partners. Please go ahead.

Leo Mariani: Hey guys, I was hoping to see if we get a little bit more of a fulsome update on Zama. I guess in a handful of weeks, you guys are kind of approaching the deadline for FID here. I know you guys have been talking about potential joint operatorship of that project for a while, does it seem like it’s going to come to fruition here?

TimDuncan: Yes, it’s getting closer. I mean, look, there’s probably more collaboration than we’ve seen in a long time, which we think is great for the partnership. It took some time to get Pemex fully caught up in what we’re doing when we were the operator. And look, we’re supporting them in every way we can to get them prepared to put in the final development plan. So just to kind of a little point there, Leo, just to make sure we have it accurately. The deadline is for the partnership through Pemex to put in the final development plan, then it goes through the regulatory C and H approvals and then after that, you can reach FID. So this step, which is a huge step is to get everything in front of the government. And, then yes, we’ve been focused on integrated project teams and I think as we can get everything put in place get everything rolled out, we can talk to the market about ultimately what it all looks like, but I think the level of collaboration is fairly strong.

And again, all that’s positive for the project.

Leo Mariani: Okay, that’s good to hear. Can we get a little bit more information on Pancheron? Do you guys have any type of pre-drill estimate in terms of how big that can be, I know it’s 30% interest for which is I think pretty close to what your target is on these exploration-type prospects, but just trying to get a sense, is this something that could be a couple of 100 barrel — barrel type of gross project here and I’m assuming this is oil as well?

TimDuncan: Yes, that’s the case. I mean, look, you’re in a fair way where there’s Oxy has a large position, your Oxy has a large working interest. We have worked with the partners on what kind of feel like think it’s appropriate to disclose before we drill it and in this case, I think what I would tell you, it’s certainly high impact, it’s got large geological structures, it’s underneath salt and so you can kind of imagine what type of project that would look like to be of interest certainly Oxy and us as well. There is ample infrastructure in the area Heidelberg for example, in the area. So what makes us interesting is you’re in a large geological fairway, subsalt, oil-weighted around near facilities in a big acreage position. So again not every project is something that we’ve got out specifically what that range will be, obviously, we have one internally but I think we put this one on the kind of a high-impact ledger if it works.

Leo Mariani: That’s helpful. And then just turning to CCS here. You guys spoke about this a little bit in terms of your prepared remarks, but I think you guys had always kind of said, hey, if things work out potentially might secure a deal when the emitter kind of around year-end ’22. I guess we’re a couple of months into ’23 at this point in time. Can you maybe just kind of talk about confidence levels in getting a couple of deals with the emitters this year, is that generally what we should expect? Do you think those are more likely to be first half ’23 events, obviously you’ve got the bigger facility now which provides redundancy but just hoping to get a little more detail around how some of these conversations with emitter are going.

Robin Fielder: Yes no, I think the discussions are moving along quite well. Recall that the Inflation Reduction Act was signed last August and so those who were thinking about it, really jumped into feasibility studies on the capture for their various facilities and so some of those are even moving into pre-FEED now and so while that work ongoing. We’re starting to see some more of these like I said, the plans request for proposal processes but even having some more discussions on some of these greenfield investments where folks are thinking about investing here along the Texas and Louisiana Gulf Coast to develop their Blue product, whether it be fuel or other product and some of the kind of discussions are underway too. So I think there’s a lot of new energy in this whole space right now after the Inflation Reduction Act.

We are seeing a lot of peers come in, wanting to also participate in different projects but it really puts the focus back on the U.S. versus some of these other international opportunities. So it’s been, it’s heated up the dialog and I think it’s just giving people some more data to look through as far as doing some — completing some of these FEED studies and understanding their cost of capture.

TimDuncan: And look, some of the industrial emitter are running more fulsome processes as well, which is totally understandable. I think the good news for us relative to where we were six months ago is the incentive structure I think is working, it’s opened up a bigger market and we’ve got a bigger asset. We absolutely kind of the next step obviously is to pull in and announce those contracts, but we’re confident that it’s coming. We’re confident who we’re partners with and we’re confident in the assets. Do you have something else, Robin?

Robin Fielder: As I mentioned, some of those customers there are several that are seeking some funding or loans from the Department of Energy. So they’re engaged in some of those processes. Tim mentioned and we put in our press release that we participated in a DoE project with the Port of Corpus Christi, we will be receiving a grant there to do a feasibility study on our storage locations to start off a CCS solution for that region, which is really right for additional investment and export out of the port itself. So again we’re putting everything in the right order, getting the right steps made to make sure that we’ve got the transport and storage solutions ready to go as the customer base starts to make their call.

Leo Mariani: Okay, that’s helpful for sure. And I guess just on your new CCS project in Southeast Texas. I guess that’s fairly contiguous with Bayou Bend. I think you guys have a 25% interest in Bayou Bend, is it kind of the same interest and kind of this new sort of much larger add-on piece here?

Robin Fielder: So this is all onshore. So we’re talking about East Texas onshore. So it’s separate from Bayou Bend but we like the opportunity there to be able to move volumes to different areas. I mean that’s going to be a key feature of many of these storage locations in our portfolio whereby we can have agreements to move volumes to different stores. Again, it’s about that operational assurance that our customer base is looking for that we can keep those CO2 volumes moving. So again, great that we can address two industrial regions both Beaumont Port Arthur and Houston Ship Channel. And so really ideally situated there in the Southeast Texas onshore space.

TimDuncan: Yes, look there is some tightening on the final agreements there, that specific to your question on working interest should be no less than what we’re doing by Bayou Bend but let us wrap that up and we’ll come back to the group and come back to the market and finalize all that. I think Chevron talked about it yesterday on their Analyst Day. I think there’s a quick slide out there on the acreage set, but it’s an exciting development, and I think it’s exciting partnership and its leadership position. So it checks all the boxes. And then as everything gets tightened up, we’ll come back to the market.

Leo Mariani: Thanks, guys.

TimDuncan: All right, thanks, Leo.

Operator: This concludes our question-and-answer session. I would like to turn the conference over to Tim Duncan, President and CEO for any closing remarks.

Tim Duncan: Okay. Thanks for joining the call. It’s going to be a very busy 2023. I think it was a long call. There’s a lot going on both in recent successes in our drilling program and exciting opportunities and what we’re doing in the capital program. The wells we’re trying to bring online and the impact will have on 2024 and the rapid growth of the CCS business. A lot to do, the team is hyper-focused on it. I appreciate everyone’s support and we look forward to coming back with updates.

Operator: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.