W&T Offshore Inc (WTI) 2021 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the W&T Offshore Second Quarter 2021 Conference Call. (Operator Instructions) This conference 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.

Thank you, Drew. 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 second quarter 2021 financial and operation 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 second quarter 2021 earnings release that we issued yesterday for disclosures on forward-looking statements and reconciliations of non-GAAP measures.

At this time, I would like to turn the call over to Tracy Krohn, our Chairman and CEO.

Thanks, Al. Good day to everyone, and thanks for joining us for our second quarter 2021 conference call. So I have with me today Janet Yang, our Executive Vice President and Chief Financial Officer; William Wiliford, our Executive Vice President and General Manager, Gulf of Mexico; Steve Schroeder, our Senior Vice President and Chief Technical Officer; and Stuart Obkirchner, our Director of Geosciences. They're all available to answer questions later during the call.

So we continued to deliver strong operational and financial results in the second quarter and believe that the improved commodity price environment and our commitment to expanding margins will lead to a very good second half 2020 -- 2021. We continue to generate stronger adjusted EBITDA and have reported $58.7 million of free cash flow thus far in 2021.

Operationally, we performed quite well, and production was above the midpoint of guidance and it increased quarter-over-quarter, even without any newly drilled wells coming online. We're very pleased with higher commodity prices, but our focus remains on operational excellence and free cash flow generation. We have an outstanding asset base, and we will continue to maximize the value of our assets.

So looking at our midyear 2020 reserve report prepared by Netherland, Sewell, who is our independent reserve engineering consultants, W&T's reserves and PV-10 value increased meaningfully. SEC's proved reserves as of June 30, 2021, totaled 158.9 million barrels of oil equivalent compared with 144.4 million barrels of oil equivalent at year-end '20. About 36% of midyear reserves were liquids and the balance was natural gas. Approximately 87% were classified as proved developed producing. Strong positive revisions to previous estimates from field performance of 6.5 million barrels of oil equivalent in the first 6 months of 2021 nearly offset year-to-date 2021 production of 7.3 million barrels of oil equivalent without any additional drilling to date in 2021. This shows the quality and significant value of our asset base. Notably, we have spent minimal capital over the past 12 months, and we continue to see positive reserve revisions.

In addition, the midyear report reflected 15.3 million barrels of oil equivalent of positive revisions due to SEC price changes resulting from the significant recovery in both oil and natural gas prices. The PV 10, excluding the impact of ARO of our midyear proved reserves, utilizing SEC pricing was $1 billion. That's an increase of 39% compared with $741 million at year-end 2020. The midyear 2021 SEC reserves and PV-10 were based on an average realized crude oil price of $47.78 per barrel compared with $37.78 a year in 2020 and an average realized natural gas price of $2.50 per Mcf compared with $2.05 at year-end 2020. So, utilizing NYMEX strip pricing as of July 1, 2021, midyear proved reserves were 165.7 million barrels of oil with a PV-10 of $1.5 billion. Midyear 2021 NYMEX strip pricing as of July 1, 2021, was based on an average realized crude oil price of $57.80 per barrel and an average realized natural gas price of $2.96 per Mcf.

So turning to our operational and financial results, we had good second quarter results as we continued to operate efficiently in the improved commodity price environment. We reported $18.7 million in free cash flow for the second quarter of 2021 and have now generated almost $60 million in free cash flow for the first half of 2021. Adjusted EBITDA was 49 -- EBITDA, rather, was $49.8 million in the second quarter of 2021, and we've generated $107.3 million in adjusted EBITDA in the first half of 2021. While we reported a second quarter net loss of $51.7 million, or $0.36 per share, this was largely driven by a $66.1 million unrealized commodity derivative loss. Excluding primarily the unrealized derivative loss, our adjusted net income was $2.2 million or $0.02 per share.

In addition to the strong quarterly results, we also completed the financial transaction of Munich Re in May that meaningfully improved our financial flexibility by more efficiently utilizing the collateral value of our Mobile Bay area assets. We transferred 100% of our Mobile Bay area producing assets and related gas treatment facilities to wholly owned special purpose vehicles in return for net cash proceeds from a $215 million virtually nonrecourse term loan to the SPVs at a very competitive fixed interest rate of 7%. This allowed us to pay off our existing RBL of $48 million and added significant cash to the balance sheet. Through our 100% ownership of the SPVs, we retain the upside value in the assets transferred. We still plan to drill new wells in Mobile Bay, and we will benefit from the potential additional cash flow from those new wells as we will receive quarterly dividends back to W&T after paying principal and interest on the loan and building a debt service reserve.

We entered into a series of natural gas derivative contracts to cover debt service through the term of the loan. This transaction doesn't impact us operationally and allows us to take advantage of the long-lived nature of our Mobile Bay assets. Additionally, it provides long-term capital without maintenance covenants or borrowing base redetermination requirements and with no covenants at the parent level. But, most importantly, it provides us to dry powder we need to continue to accretively grow W&T through attractive property -- producing property acquisitions.

Over the years, we've built a tremendous group of assets through organic growth and targeted acquisitions. We are actively looking at opportunities that meet our criteria, especially those that are providing solid foundation for our ability to generate free cash flow. We've integrated 2 strong acquisitions over the past 2 years, and we'll look for more of those types of opportunities in the future. We believe that market conditions in the Gulf remain very favorable for additional accretive acquisitions. Our immediate access to a significant cash balance and continued strong cash flow generation have well positioned us to actively pursue these opportunities.

So, turning to the production for the second quarter of 2021, W&T produced 40,888 barrels of oil equivalent per day, or 3.7 million barrels of oil equivalent. That's an increase of 3% compared to 39,657 barrels of oil equivalent per day in the first quarter of 2021. Production was above the midpoint of our guidance due to better runtime efficiency and uplift from the completed workover. Liquids production comprised 45% of total production in the second quarter of 2021.

So looking ahead to the third quarter of 2021, we're forecasting our production to be in line with the second quarter and average 38,500 to 42,500 barrels of oil equivalent per day. Our operations team are doing a really good job of maintaining our production despite not having any new wells coming online until later this year. We're tightening our full year 2021 production guidance range to between 39,000 and 41,000 thousand barrels of oil equivalent per day.

Our lower production decline profile allows for reductions in capital expenditures without significantly impacting near-term production levels. In the second quarter, we spent $4.3 million. And for the entire first half of 2021, we've only spent $5.9 million of our $30 million to $60 million full year capital budget. We have an exciting new drilling opportunity in the second half of the year, and I'll give more details on that later in this call. So for the second quarter of 2021, our average realized sale price per barrel oil equivalent was almost unchanged from the first quarter.

Our second quarter 2021 average realized crude oil sales price increased to $65.11 per barrel from $56.73 per barrel in the first quarter of 2021 and $21.67 in the second quarter of 2020. It's great to see $70 crude today after actually going negative on NYMEX just a year ago. Our natural gas liquids sales price is also up slightly from the first quarter of 2021 to $26.18 per barrel, offset by lower natural gas prices of $2.66 per Mcf compared to $3.35 in the first quarter.

So excluding the effect of hedges, revenues for the second quarter increased quarter-over-quarter by 6% to $132.8 million, driven by increased production. Despite the improved pricing environment, our focus will remain steadfast on capital discipline, operational excellence and, most importantly, free cash flow generation.

So in March 2021, we issued our inaugural corporate ESG report. Since Day 1, we've been committed to developing and producing oil and gas resources in a safe and environmentally responsible manner, all the while meeting our -- or exceeding all regulatory requirements. These core values have guided our success and provided the foundation for W&T to grow into a trusted operator in the Gulf of Mexico, a generous partner to the communities where we operate and good stewards to the environment.

With that in mind, we're working on -- with the new administration and BSEE to ensure that we have safe facilities that minimize the impact of the environment in which we operate. We've seen some reductions in operating costs and GHG emissions associated with the consolidation of our 2 Mobile Bay treating facilities into one plant in early 2021. However, we've seen increases in other operating expenses due not only to increased industry activity levels, but also in conjunction with ensuring that we meet or exceed regulatory requirements. Additionally, we're increasing our P&A activity this year, and we'll have more capital costs associated with asset retirements. We're expecting to spend $25 million to $35 million this year, of which we have spent only about $11.2 million through June.

We established a multidisciplinary ESG task force that contributed to creating our initial ESG report, and they have the ongoing responsibility to monitor our adherence to our ESG standards and formally communicate their findings on to me and our Board and to suggest opportunities for further improvements. We're acting on their recommendations and continue to improve on our commitment to powering America safely and in a more sustainable manner for many years to come. I'm also pleased to say that their efforts in creating our first ESG report recently resulted in a meaningful improvement in one of our third-party ESG ratings by a highly regarded ESG rating agency.

So turning to costs, lease operating expense, which includes base lease operating expenses, insurance premiums, workovers and facilities maintenance, was $47.6 million in the second quarter of 2021 compared to $42.4 million in the first quarter. We'll continue to operate efficiently and do so in a rising price environment. We may see some cost increase in the near term. Additionally, recently BSEE has prioritized certain types of maintenance repair for all Gulf of Mexico operators due to corrosion-related incidents of platforms operated by other companies. Nonetheless, we haven't changed our annual LOE guidance of $158 million to $174 million. We will remain vigilant in our cost containment initiatives, and we'll control the costs that we can without impacting safety or the environment.

So G&A was $14 million in the second quarter of 2021, which was at the low end of our guidance range. While we were at the lower end of the range, G&A costs were up compared to the $10.7 million in the first quarter of 2021, which benefited from a $2.1 million employee retention credit associated with the CARES Act. We've increased our full year 2021 guidance range for G&A a little less than 4%, which takes into account the recent Mobile Bay financing and other ongoing M&A activity. Additional details on our expense guidance are in the earnings release we issued yesterday.

So turning to the balance sheet and cash flow, net cash provided by operating activities for the 3 months ended June 30, 2021, was $1.2 million, which was reduced by $25.6 million in derivative premiums paid for our hedging activities in conjunction with the new first lien secured term loan to retain the upside of the higher natural gas prices, while locking in floors for natural gas prices for production from Mobile Bay properties over the next 7 years.

Higher ARO settlements and expense and increased operating expenses, considering each $1 of gas price increase could cost the company $165 million in hedge losses, we believe the call and put premiums are a good insurance cost to protect us over the next 7 years. As I stated earlier, in the second quarter, we utilized a portion of the proceeds from the Munich Re transaction to pay off the remaining $48 million RBL balance.

So working with our bank group, we recently executed an amendment and waiver that defers the spring 2021 borrowing base redetermination under our RBL until early October. During the interim time period, we've agreed to not access the credit facility, which remains fully undrawn. But given our very strong balance -- cash balance of $209 million as of June 30, 2021, we don't see a need to access the revolver.

We're also actively monitoring the debt capital markets and intend to seek financing with longer tenures and market-based covenants to provide even more liquidity in the future. Current total debt is $754.7 million, consisting of the balance of the Munich Re term loan of $208.3 million and $546.4 million of 9.75% senior second lien notes due 2023, net of amortized debt issuance costs for both transactions. W&T is currently in compliance with all applicable covenants of the credit agreement and the senior secured second lien notes indenture.

Now turning to operations during the second quarter of 2021, we performed 1 workover at with Mahogany that in total added approximately 700 net barrels of oil equivalent per day to production. That's a very strong result. It is both highly economic and helps us to mitigate natural decline. We plan to continue to perform workover recompletions as they are often some of the best economic projects in our portfolio. The successful Cota well that we drilled early last year at East Cameron 338/349 is currently in the development phase of the project and is expected to be on production in this year's fourth quarter. The well is in over 290 feet of water, was drilled to a total depth of over 6,000 feet while encountering approximately 100 feet of net oil pay. We had an initial 30% working interest, but our increase will -- our interest will increase to 38.4% once the well is brought online and certain performance thresholds are met.

So, while we continue to proceed with preparing our internally generated prospects for potential drilling later this year and into 2022, a third-party-operated opportunity in Mississippi Canyon recently emerged that we're excited about. So based on our assessment, we believe the well has the highest potential, but relatively lower risk opportunity located in the Flex Trend area where W&T has had significant experience and success. Furthermore, assuming success, it could derisk additional drilling opportunities that W&T has in the area. This prospect was identified using high-quality 3D seismic and reprocessing and has multiple objectives located beneath the salt overhang. This high potential oil play ties directly to analogous fields in the area and has significant upside. We have a 25% working interest, and the well has just spudded. In summary, we believe this is an excellent opportunity with good upside potential that could also allow us to derisk existing organic opportunities.

The rising price environment presents many opportunities for W&T. We have a premier portfolio of both shallow water and deep water properties in the Gulf of Mexico with low decline rates and significant upside. There are many opportunities for acquisitions in our focus area, and we constantly look at any that can meet our stringent criteria. Our disciplined approach to growth has allowed us to navigate many cycles in the past. We remain opportunistic, and we'll look for ways that we can add value to W&T. We've always focused on generating free cash flow by operating efficiently and executing our long-term strategy to maximize shareholder value.

So production is up, reserves are up. Prices are up over $100 per barrel since April 20, 2020. Differential spreads are down. Acquisitions are likely going forward as bid-ask spreads have narrowed. And we're also seeking growth organically in an area in-basin that we know very well armed with better data. We're quite confident in our ability going forward to gain low-cost financing when it's necessary to do so. There's plenty of tank on the sidelines looking for yield, and the Gulf of Mexico is an excellent place -- or an excellent play for cash flow as well as a lower carbon intensity.

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. This alignment of interest ensures that we are truly incentivized to maximize shareholder value and mitigate risk.

Operator, if you would, we can now open the lines for questions.

(Operator Instructions) The first question comes from John White with ROTH Capital.

It's really nice to see all the free cash flow, so congratulations on that. Looks like you're really focused on it.

Thanks, John.

I could see with these higher crude prices -- are you seeing any oil service cost pressure starting to build?

Yes. We're seeing it in transportation -- boats, helicopters at this point. There is, of course, some seasonal creep in the prices because this is the time of the year when we get the most amount of work done, second, third quarters. So it's a little bit hard to discern that, but I see price is going up more in the -- on the transportation side of it at this point.

I was excited to see the announcement about your new well in Mississippi Canyon. As you mentioned, you've certainly got a lot of experience there with your Matterhorn and Mississippi Canyon 698 and several other blocks. Would you want to disclose what block this new well is in?

Yes. I'd like to, John. I just don't have permission right now from the other interests in the well to do so. So I'm a little bit reticent to do that. We haven't given out the names or depth or anything like that. But if you did a little research, it wouldn't be hard to figure that out, I don't think, but I just haven't gotten that permission. And, actually, I didn't seek it. So I didn't think it was best to do that since the well just spudded a day or so ago.

Okay. Totally understand. Any ballpark time line on when we might hear the results? Or is that being held tight also?

No, I'm hoping we'll have something by the end of September.

Okay. Well, we don't see many wildcats nowadays, so it's exciting to see (inaudible).

Yes, it is. It's a very high-quality prospect.

The next question comes from Michael Scialla with Stifel.

Wondering if you could just give any -- I want to see if you can give any kind of detail on the CapEx for the second half. You're obviously second half weighted with the spending. Should we assume more of that is third quarter or fourth quarter?

I think more in the third quarter. We've got a little bit to spend in the fourth quarter because of Cota, third and fourth quarter because of Koda, but more primarily in the third quarter.

Got it. So you got the [non-op] well in the third quarter and the Flex Trend and then assume some additional workovers in the second half. You got the Koda well fourth quarter. Anything else that we should be thinking about on . . .

Yes. We'll be doing the development on the Koda well also.

Great. Okay. And then you had mentioned in your prepared remarks on looking at the debt markets improving. I just want to get kind of your view on the high-yield market now, maybe as that compares to the new SPV financing opportunity that you have.

Yes. The debt markets have been pretty white hot this year. So I think it bears taking a look at and that's exactly what we're going to do. I think we should avail ourselves of different options. That's kind of what they pay me for. So I'm reticent not to do it. I think that there's a really -- we see a lot of money on the sidelines looking to chase yield, and I always think that it's probably better to go find money when you can rather than when things are turned around.

(Operator Instructions) The next question comes from Jeff Robertson with Water Tower Research.

I was wondering if you could talk a little bit more about the prospects market in the Gulf of Mexico with the new addition to your capital program in terms of -- are there -- what kind of promotes people are looking for? And also, are you seeing opportunities to add prospects to your 2022 capital program?

Yes. So the first part of your question on promotion, we're not seeing really heavy promotes. I think everybody is fairly tentative on their drilling programs at this point in time. Prices are up. So I think that guides a lot of the thought process. The most recent well that we're talking about drilling -- that we are drilling right now was an opportunity that came to us in an area that we know a lot about and were able to take advantage of the technology that we have with the data in-house to enhance that. So I'm fairly confident that we'll see some more things like that in the future. And I assure you that we're looking at it in-house and from others as well.

On this well that you're -- just spud, Tracy, if it's successful, is this something that adds to the production profile in early 2022 or late 2022 or even earlier this year?

Yes. It's a little bit of a -- well, not a little bit. It's a big function of the size of the discovery because it makes a difference whether we [tie back] subsea or whether we go ahead and install a facility.

Okay.

And if we're worried about installing the facility, that makes this a lot bigger. Okay?

Yes. That's potentially a good problem.

That's a quality problem. You're right.

And we have a follow-up from Michael Scialla with Stifel. Please go ahead.

You just -- you mentioned also that you do have the intent now to drill at Mobile Bay. Just wanted to get a sense of -- is that something that could happen next year? Or are you thinking longer term?

We're not quite sure yet. We've got some permitting things that we need to work through to get that done. The increase in the price of gas has certainly made that more relevant. But there are some permitting things that we need to do in that area. So I would suspect that permitting and prices of gas will make that more evident on more than one well. So we're relatively confident that this is something we get done in the next -- or at least we get the permitting done in the next 18 months at this point, for at least the first well. That would be our thought process at this point in time.

We see prices as staying up for a good while. That's one of the reasons why we entered into all these call contracts that -- or bought the calls rather, to assist us in some of our thought process around pricing on gas. We're pretty bullish on it. So hopefully, we get -- these are fairly complex deep wells. They're over 4 miles deep and it's hot pressure and you've got a little H2S in it as well.

Great. And since you mentioned the permitting process, can you just talk in general about the regulatory environment now, how things have changed at all with the new administration?

Yes. This is more to do with the State of Alabama, but also the Feds, too, as well as several other agencies that need to pass muster on the process. And I recall a lot of the permitting things that we had to do at Mobile when we discovered the field nearly 40 years ago. And although I will say that I'm pretty confident that the State of Alabama would like to see some wells drilled out there, and we're looking forward to doing it.

I guess, more broadly in terms of your overall operations in the Gulf, are you seeing any greater challenges in getting permits? Or, I guess, obviously, the whole bidding process has been put on hold for a while with resale, but anything else in terms of the regulatory environment?

Yes. The lease sale -- of course, new leases aren't being sold right now or aren't being auctioned. But existing permits or existing leases, we are able to get permits. It takes a little bit longer. The regulatory folks aren't back in their offices yet. So I'm sure that will straighten out as that gets more in line with having people closer together and able to function more efficiently in a group environment as opposed to on the phone and via video. A lot of this requires looking at maps and details that are really hard to do on a video screen as opposed to together in a room.

There are no further questions at this time. I would like to turn the conference back over to Tracy Krohn, Chairman and CEO, for any closing remarks.

Thank you, operator. We appreciate everybody's attention today, and look forward to speaking with you again in the near future. Thanks so much. Goodbye.

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