W&T Offshore, Inc. (NYSE:WTI) Q4 2022 Earnings Call Transcript

W&T Offshore, Inc. (NYSE:WTI) Q4 2022 Earnings Call Transcript March 8, 2023

Operator: Ladies and gentlemen, thank you for standing by, and welcome to the W&T Offshore Fourth Quarter and Full Year 2022 Conference Call. During today’s call, all parties will be in a listen-only mode. This conference call is being recorded, and a replay will be made available on the company’s website following the call. I would now like to turn the conference over to Al Petrie, Investor Relations coordinator.

Al Petrie: Thank you, Joe. And on behalf of the management team, I would like to welcome all of you to today’s conference call to review W&T Offshore’s fourth quarter and full year 2022 financial and operating results. Before we begin, I’d like to remind you that our comments may include forward-looking statements. It should be noted that a variety of factors could cause W&T’s actual results to differ materially from the anticipated results or expectations expressed in these forward-looking statements. Today’s call may also contain certain non-GAAP financial measures. Please refer to the earnings release that we issued yesterday for disclosures on forward-looking statements and reconciliations of non-GAAP measures. With that, I’d like to turn the call over to Tracy Krohn, our Chairman and CEO.

Tracy Krohn: Thanks, Al. Good day to everyone, and thank you for joining us for our year-end 2022 conference call. So, with me today are Janet Yang, our Executive VP and Chief Financial Officer; William Williford, our Executive VP and Chief Operating Officer. So, I’m really pleased to report that 2022 is one of the best years in our long and profitable history. Our strategy has always been pretty simple: generate free cash flow, maintain high-quality conventional production and opportunistically capitalize on accretive opportunities to build shareholder value. So, our ability to integrate producing property acquisitions while maintaining strong operational excellence were significant drivers in our outstanding financial results in 2022.

Here are the key things we’ve accomplished. We reported full year 2022 net income of $231.2 million or $1.59 per share and generated record adjusted EBITDA of $563.7 million and a year-over-year increase of 156%. We’ve generated free cash flow — positive free cash flow for 20 consecutive quarters. And in 2022, we produced $376.4 million of free cash flow, which was more than 4 times what we did in 2021. But we completed two attractive property acquisitions, producing property acquisitions in early 2022, and we’ve successfully integrated them into our operations, and these acquisitions have already paid out as of August 2022. We increased full year 2022 production to 40,100 barrels of oil equivalent per day. We grew cash and cash equivalents to $461.4 million at year-end.

So, hand in hand with our growth in cash has been a significant reduction in net debt. Our net debt was down more than 50% year-over-year to $232.1 million as of December 31, 2022. Our net debt to trailing 12 months adjusted EBITDA continued to improve significantly to 0.4 times compared to 2.5 times a year ago. That’s well below our stated goal of below 1 time per year-end. And in January of this year, we paid off our 2023 second lien notes and issued new 2026 second lien notes, significantly reducing our interest payments and debt moving forward. So, we clearly had an outstanding year, thanks in no small part to the ability of both our operations and finance teams to execute at a high level. This combination of strong production and continued very good pricing resulted in our outstanding adjusted EBITDA and free cash flow numbers.

To put this in perspective, the $563.7 million in ’22, adjusted EBITDA was almost 50% higher than the total of full year’s 2021 and 2020 combined, which totalled $383.7 million. So, coupled with our ability to pay down debt and improve our balance sheet, we’re clearly in a much stronger financial position today, and we remain focused on operational execution to build on these solid results. So, turning to our year-end reserve results. I’d like to point out that we continue to see positive well performance in technical revisions, which demonstrates the strength of our world-class conventional Gulf of Mexico assets. This also directly points to our ability to enhance production and our reserve base through operational excellence. For year-end 2022, we reported SEC proved reserves of 165.3 million barrels of oil equivalent, which included 7.3 million barrels of oil of equivalent — of positive performance revisions and an increase of 6 million barrels of oil equivalent due to the two acquisitions we made early in 2022.

We also had strong positive pricing revisions of 9 million barrels of oil equivalent. So, in total, we added 22.3 million barrels of oil of new reserves, which replaced 153% of our 2022 production of 14.6 million barrels of oil equivalent. So, our all-in reserve replacement cost for 2022 were $4.10 per barrel oil equivalent and have averaged a very reasonable $2.85 per barrel of oil equivalent over the last three years. We say that again, $2.85 per Boe over the last three years. So, we’re particularly pleased with these results since last year, we focused on reducing net debt while completing bolt-on acquisitions and less on drilling. Where you see the biggest impact of higher pricing is in the PV-10 value of our SEC proved reserves, which at year-end ’22 nearly doubled to $3.1 billion.

Approximately 36% of our year-end 2022 SEC proved reserves were liquids, with 25% crude oil at 11% NGLs, and we had 64% natural gas. The reserves were classified as 75% proved developed producing, 13% proved developed nonproducing and 12% proved undeveloped. W&T’s reserve life ratio at year-end ’22 based on year-end ’22 proved reserves in 2022 production was 11.3 years. So, overview is 11.3 years. We believe we have built a sustainable group of high-performing GOM assets that will continue to provide meaningful cash flow to our shareholders for many years. So, in February 2022, the company closed an acquisition of central GOM federal shallow water producing assets for approximately $34 million after taking into account normal and customary post-effective-date adjustments.

This acquisition consisted of an average of 80% working interest in over 50 different properties to gross producing wells, and that was at Ship Shoal 230, South Marsh Island 27/Vermilion and South Marsh Island 73. W&T has operated that for the past year. In April 2022, we acquired the remaining 20% working interest in these assets for $17.5 million. Acquisitions are a core pillar of how we create value. And this is another example of what we look for when we’re evaluating an acquisition. These assets provide a solid base of proved reserves and produce strong free cash flow. These properties are very complementary to our existing assets. There are a number of opportunities, both near term and long term that we can undertake to maximize the value of these assets.

We also see areas of upside potential that won’t require significant amounts of capital realized. W&T is very well positioned for further acquisition activity, and we’re continuously on the lookout for deals that meet our criteria. So, we’ve used our substantial free cash flow to vastly improve our financial position and strengthen our balance sheet. At year-end ’22, our net debt-to-adjusted EBITDA ratio was down to 0.4 time, and we had available liquidity of $511.4 million. This was comprised of $461.4 million in cash and cash equivalents and $50 million of borrowing availability under our revolving credit facility. In the fourth quarter of 2022, we entered into an amendment to our credit facility, which, among other things, extended the maturity date and commitment by up to one-year January 3, 2024.

So, at year-end 2022, the company had total debt of $693.4 million or net debt of $232.1 million, net of cash and cash equivalents, consisting of the balance of the nonrecourse Mobile Bay term loan of $143.3 million and $550.1 million of 9.75% senior secured lien notes net of amortized debt issuance costs for both instruments. That’s a lot of numbers. So, entering 2023, we strengthened our balance sheet by issuing new 2026 senior second lien notes at par, totalling $275 million in a private offering and used the proceeds along with a considerable cash position to retire all $552.5 million of our 2023 senior second lien notes. This significantly reduces our interest payments, preserves our financial flexibility and further improves our balance sheet moving forward.

It’s important to note, we’re very pleased that as a result of the new debt offering, we’ve received upgraded ratings by our two existing rating agencies and received a rating from a new agency this week that was in line with those upgraded ratings. But we have the flexibility and drive powder to make additional acquisitions, drill our current process — prospects, continue to build cash or pay down debt. Because we have no long-term rig commitments or near-term drilling obligations, we have flexibility to ramp up or defer capital opportunities. In 2022, we focused on reducing net debt and invested $41.6 million in CapEx and $51.5 million in acquisitions. We’re currently anticipating our CapEx range for 2023 to be between $90 million and $110 million.

Included in this range are planned expenditures to — related to long-term lead items and funding the engineering design for our Holy Grail prospect at Magnolia as well as three shelf wells that may be drilled later this year and capital costs for facilities, leasehold, seismic and recompletions. As always, we’ll monitor commodity prices through the year and adjust our spending plans accordingly. With our modest capital range in 2023, we expect to generate meaningful free cash flow, which provides us flexibility to execute on accretive opportunities quickly. For our 2023 P&A budget is expected to be considerably less than in 2022, which was driven by obligations in prior deferrals on terminated leases. And that’s terminated leases with Bessie.

P&A expenditures in 2023 are expected to be in the range of $25 million to $35 million compared with $76.2 million in 2022. Yesterday, we provided our detailed guidance for 2023. In the first quarter of 2023, we have had several planned periodic facility and pipeline maintenance projects underway at the Mobile Bay field as well as prolonged downtime at several non-operated fields that have temporarily reduced our production volumes. Most of the non-outfield that were shut in are now back online and maintenance project is nearly complete with volumes returning to normal levels soon. We expect Q1 2023 production averaged about 33,800 barrels of oil equivalent per day. For full year 2023, we expect to produce between 37,000 and 41,000 barrels of oil equivalent per day, which is a small decrease of 3% year-over-year and flat compared to fourth quarter of 2022.

That’s being impacted by a lower first quarter volumes. We’ve focused on acquisitions over the last few years rather than on drilling many new wells. Our guidance reflects the low natural decline of our asset base compared with much higher declines in unconventional onshore reservoirs. So, on the cost side, our guidance for LOE and gathering transportation and production taxes include inflationary and supply chain pressures that we’ve seen in ’22 and expect to carry into 2023. We do believe that there are opportunities to reduce our operating costs and are working hard to reduce those future costs with an eye on safety and without deferring asset integrity work. First quarter lease operating expense is expected to be between $63 million and $70 million, which reflects some of the same cost inflation that the entire industry has faced.

First quarter cash G&A costs are expected to be between $16.5 million and $18.5 million. Before I close out the call, I’d like to talk to you about our ongoing ESG efforts, environmental stewardship, sound corporate governance and contributing positively to our employees and the communities where we work and operate our cornerstone to our culture. The ESG metrics were incorporated into our 2021 short-term incentive plan, and we’re continuing with that practice moving forward. We plan to reduce our third sustainability report later this spring, building on the solid foundation of our previous reports. In closing, we’re very pleased with how well we performed in 2022, both operationally and financially. I’d like to thank the employees working offshore and onshore W&T for one of the most successful years in our long history.

We generated great cash flow and adjusted EBITDA in 2022, and we’re poised for continued success in 2023. Our strong financial position, which was enhanced with our net significant debt reduction and debt maturity extension on remaining debt from 2023 to 2026 provides us with optionality and flexibility moving forward. Our liquidity and cash position enables us to continue to evaluate growth opportunities, both organically and inorganically, and we’re poised to execute on accretive opportunities that meet our long-standing and proven criteria. We believe the Gulf of Mexico is and will continue to be a world-class basin with strong producing assets. It’s good to see public markets starting to better appreciate offshore assets where we’ve always been focused.

Quickly, evaluating and executing on opportunities within our focus area is a pillar of our success. So, we have a premier portfolio of both shallow water and deepwater properties in the Gulf of Mexico that have low decline rates and significant upside. Our management team’s interests are highly aligned with those of our shareholders, given our 34% stake in W&T’s equity, which is one of the highest of any public E&P company. So as a shareholder, I’m excited and very encouraged about the success we had in 2022 and believe that we have a bright future in 2023 and beyond. So, with that, operator, we can open the lines for questions.

Q&A Session

Operator: And our first question here will come from John White with ROTH Capital. Please go ahead.

John White: Good morning, everyone. And congratulations on the very strong year that you had. And let me further tip my hat to your reserve replacement cost. You just don’t see companies putting up numbers like that anymore.

Tracy Krohn: Thanks, John. Thanks very much.

John White: And we get updated on a couple of things here. The Holy Grail, we’re about 30 days from the end of the first quarter. Is that going to spud this month or earlier in the second quarter?

Tracy Krohn: The reality is we’re evaluating that. We’re thinking maybe — what maybe we defer on that for a while. I like the cash position we have. I think that maybe we have a better shot at buying reserves and we do a drilling form right now. And Holy Grail isn’t going to go anywhere because it’s proved reserves that we’re drilling for. So apparently, those reserves have been there for a few million years. They can wait another year or so…

John White: And same question on the spud date for your side-track 320, is that looking to be fourth quarter or you might defer that, too?

Tracy Krohn: Yes, and yes. It might be fourth quarter we might defer it. Again, one of the reasons that we opted not to pay off all of our debt was in thinking about existing opportunities that might come up. We were in a position to pay that debt off and opted to show ourselves up with a bit more liquidity in the form of cash. So, we see in the future, we think that there’s a likelihood of maybe not a likelihood, but certainly, the opportunity to buy more reserves as opposed to go drilling for them. And if any time those are equal numbers then we’re probably going to try to buy out.

John White: Okay. I appreciate that detail. And as a follow-up, is that — you’re tilting towards potential acquisitions. Is that being driven by the oilfield service inflation trends that we’re seeing in part?

Tracy Krohn: Yes, it is. Definitely, that’s a consideration. Again, if I can drill them for about what I’m going to — excuse me, if I can buy them for about what I can drill them for, and it makes more sense to chase that. The only risk there is it’s never a guarantee that you’ll be able to buy in. So, we don’t make predictions on what we’re going to be able to buy for the year or any time in the future. But we have a pretty good history over the last four years of being able to do that. So, I’m confident a good shot at it.

John White: Indeed, you do have a good history in acquisitions, and we will look forward to seeing what you come up with. With that, I’ll pass it back to the operator.

Operator: Our next question will come from Derrick Whitfield with Stifel. Please go ahead.

Derrick Whitfield: Good morning, all and thanks for taking my question. The low declining nature of your asset base shows through in your 2023 guidance. Looking beyond 2023, how long could you sustain oil production through workovers and recompletions assuming the current lower price environment?

Tracy Krohn: That’s a great question. I don’t know if I have a pat answer for you, how long can I retain that guidance. We — the repeat is 11.3% right now. So — and it is somewhat driven by our production at Mobile Bay, which is very long-lived gas reserves. I happen to think gas reserves are a good thing to have going forward. So, I don’t know that I have a really good answer for you for how long we can reserve — we can produce at this decline reserve, this decline rate, I think you should take some part with that 11.3% RRC.

Derrick Whitfield: Terrific. And as my follow-up, you had mentioned in the press release in short and somewhat in the prepared comments about a carbon capture market opportunity. Could you perhaps expand on the roles you seek to pursue? And if you’d commit to securing poor space for Class six wells, assuming federal leases become available?

Tracy Krohn: Yes, I’m going to have more to talk about later on with that. It’s not like we’re sitting over here on our thumbs. We are. I mean, we are not sitting on our thumbs. What we are doing is continuing to evaluate the various markets. I think what people don’t really appreciate is the difficulty isn’t in putting it in reservoirs, I find that as a fairly simple exercise. The only real question is, do you put it in as a gas or as a liquid. And generally, you’re going to put it in as a liquid. These saltwater reservoirs, particularly out in the Gulf of Mexico are almost unlimited with regard to how much food or how much gas you can put into them as CO2. CO2 is a very odd molecule in that it can exist in a liquid, solid or gaseous state all at the same time.

So, there’s not a whole lot of difficulty in putting it in the ground. The difficulty stems more with regard to the first foot from the flue gas stack, okay? So that’s where the real technology is. How do you separate it out? How do you put — get it into a position where you can either liquefy it or compress it as a gas into formation? So those are the things that not a whole lot of people are talking about as regards to where the real technology is. There is technology out there for it. It’s just expensive. And I think the government has gone a long way in assisting with tax credits going up, they’ve grown from, what, about 50 to 85. But the states are lagging a little bit behind in assisting with the permitting process. So, it’s one thing to get geared up.

We have infrastructure all along the Gulf Coast, all the way from Alabama to off the coast of Texas and Louisiana and even Mississippi for that matter. So, it’s not getting it into the ground that I focus on too much. I think that’s reasonably well done and the pipelines exist to get that done. So — and they may have to be enhanced somewhat. But CO2 is relatively benign gas. It’s not going to explode. And it’s certainly — it’s well known as a molecule as to what its characteristics are. So, what’s not well known is exactly how it reacts as it touches the reservoir. But I see that as a minor issue that will be resolved with coring of the saltwater reservoirs. Most people have not cored saltwater reservoirs because they’re saltwater reservoirs.

We don’t use them to produce. We use them in this case to put a molecule of CO2 in, but we will need to know what those are reservoir characteristics. So, there will be expenses going forward with those reservoir valuations. As to where we’re doing that, I mean we’re looking off the Coast of Texas and Louisiana and Alabama at this point in time.

Derrick Whitfield: Perfect. Great color. We certainly look forward to more disclosure from you in the future on that opportunity.

Operator: And our next question will come from Jeff Robertson with Water Tower Research. Please go ahead.

Jeff Robertson : Good morning, Tracy. This might be a follow-up to Derrick’s question with respect to decline curve. You all replaced roughly 50% of 2022 production just with positive performance revisions. Can you talk about — do you have an assessment of W&T’s probable reserves and what your production performance implies for bringing some of those probables on to proved in years to come?

Tracy Krohn : Yes. Generally, what we look for and think about is almost like proved reserves is the portion of probable reserves that we don’t have to spend in CapEx on that are going to occur as a result of the way that these reserves are booked for offshore traps. So onshore, you have blanket areas of reserves that if you drill a well on a lease and you own the surrounding leases, you get a multiple on those reserves as you drill that one lease. Offshore, you don’t enjoy that same type of evaluation because they are actually geologic traps as opposed to massive stratigraphic traps. And thinking about offshore as it relates to probable reserves, we’re generally under booked on the front end. And we would see these as cash flow in the future.

And then after the passage of time, we’re able to book more reserves. So that’s one of the things that defers that decline curve. And it’s also one of the things that brings us cash flow. As an example of what we see, I usually put it in the presentations as an illustration of down dip oil water contact. And it could be gas water contact as well. But you have a drive mechanism in the Gulf of Mexico, Gulf of Mexico water drive that’s prevalent in many, many places. So, we get a lot of those reserves from that water drive rather than drill another well, just to prove up reserves. We just forgo that expense and let Mother Nature help us get it into the wellbore and turn it into cash flow. So, this is a known feature of our reserves over many decades that occurs for us.

So, we generally don’t get much credit in the market for that, and I appreciate the question.

Jeff Robertson: With respect to acquisitions, Tracy, can you just give an update on what you see as the state of the market for properties that might fit W&T’s criteria?

Tracy Krohn : Sure. I mean, this is — as I stated earlier, one of the things that we thought about with regard to our debt was not painted all off in favor of having that additional liquidity. So, I feel pretty confident about the things that we’re looking at. And remember, we’re primarily Gulf of Mexico. So fortunately, we have the ability to look not only in deep water, but also in shallow water as well. And we’re pretty agnostic about whether it’s oil and gas. All we care about is — or whether it’s deep water or shallow water, all we really care about is how much money it’s going to generate. As a side to that, I would tell you that offshore is an excellent basin because our emissions are generally less. We’re burning gas generally as natural gas as a fuel source as opposed to hauling diesel out or utilizing additional electricity off the grid.

So, we are more efficient in that sense. And plus, we don’t use the upwards. We don’t frac. We don’t flare. We have put this gas in the pipeline and go sell it. There are exceptions with regard to new wells that come on or system upsets that we have to deal with. We have to permit that, and it’s usually very short time to get that done. But I’m really encouraged about what we’re seeing with regard to acquisitions. I don’t generally comment on it too much because we signed these confidentiality agreements. And suffice to say that we’re generally in data rooms fairly often. We’ve been around for a long time. So, they’re not always data rooms that we’re attending some of them are solicited or unsolicited bids. So, we look at a lot of different ways to buy these.

I’m encouraged because I see a bit of stability in oil and gas pricing at the moment, even though they’ve come down. So, I think that in the future, prices will be better. I can’t tell you when or how much better, never been very good at projecting that. We did this Anchor acquisition recently and paid off in seven months. And that was a bit lucky because when we bought it prices were down and as we acquired the properties, prices immediately went up. I’ve had to go the other way, but we always seem to come out ahead. So yes, I still, I am very encouraged by what I’m seeing with regard to acquisitions. I’m a little reticent to give you precise information, but I certainly appreciate the question.

Operator: Our next question here will be a follow-up from John White with ROTH Capital. Please go ahead.

John White : Thank you, operator. Following up on Jeff’s question on acquisitions. Is there a way you would characterize potential who you believe potential sellers are in terms of private equity-sponsored companies or major oil companies making divestitures?

Tracy Krohn : Yes. Great question, John. It’s both and others as well. I don’t know how to handicap one or the other. But a lot of these funds have had properties for a period of time. And as you know, they need to go ahead and sell them at some point in time and generate that ultimate return. We’ve made a pretty good living over several decades of dealing with major oil companies and successfully purchasing those properties. And part of that reason is that we’re good custodians. Nobody has ever had to be concerned about whether we’re going to perform our P&A obligations. We’ve done over $1 billion worth over the years, and I think that’s a pretty good market. I think we’ve done more actual abandonment than anybody in the Gulf of Mexico as expenses as an E&P company.

So, on our own nickel. So, I think that’s important considerations. We’ve dealt with major companies. We’ve dealt with large independents. We’ve dealt with fines. We bought reserves in a bunch of different ways. So, all of those are on the table right now.

John White: Okay, I appreciate that. Thank you. I’ll pass it back to the operator.

Operator: And our next question will be another follow-up from Jeff Robertson with Water Tower Research. Please go ahead.

Jeff Robertson : Tracy, my follow-up is with respect to the MOU, you all announced back in May with Korea National World Corp. With the financing of the 23 notes behind you, I’m guessing that you have a lot more flexibility in terms of the types of opportunities you’re able to evaluate with them. And just wanted to check on that? And then secondly, when you think about CCS opportunities in the future, are they a potential partner for W&T and opportunities you might pursue in that realm?

Tracy Krohn : That’s a possibility. We have discussed that in the past, not directly as a precise project, but we have discussed, I mean, the Koreans are cognizant of their emissions and this being a state entity, the sovereign entity, it’s incumbent upon them to think about that. It’s incumbent upon us to think about it. I have to think that Korea National oil company has a lot of great minds that look at things worldwide. So, we’re encouraged by that. We’re encouraged by other things that we might be able to do with them that haven’t been discussed yet. As we think about going forward, it’s a national oil company. And it takes them not very long, really to decide what they want to do. They are very precise and they’re very confident about how they approach different projects, and we’re excited to have that association.

And we believe that we both add something to it. We’ve talked about a number of different things. We — W&T has been — as you’re right — as you observed, W&T has been in a position of really being more concerned about its debt and financial liabilities going into 2023 and closing that out. And now that we’ve accomplished that, and we have a little bit more time to focus on that.

Jeff Robertson : Thank you, Tracy.

Operator: And this concludes our question-and-answer session. I’d like to turn the call back over to Tracy Krohn for any closing remarks.

Tracy Krohn : Look, I appreciate everybody listening in. I appreciate all the questions. We’re extremely encouraged and excited about what we see in front of us. Prices go up and down. We believe that we provide a service to our country and to our shareholders as a very confident in skilled oil and gas operator in the Gulf of Mexico, we look forward to doing that for many years. And with that, we’ll talk to you again soon.

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