Gulfport Energy Corp (GPOR) 2021 Q3 法說會逐字稿

Greetings. Welcome to the Gulfport Energy Corp. Third Quarter 2021 Conference Call. (Operator Instructions) Please note that this conference is being recorded. I will now turn the conference over to your host, Tommy Renouard. You may begin.

Thank you, and good morning. Welcome to Gulfport Energy Corporation's Third Quarter of 2021 Earnings Conference Call. I'm Tommy Renouard, Senior Analyst of Investor Relations. Speakers on today's call include Tim Cutt, Chief Executive Officer; and Bill Buese, Executive Vice President and Chief Financial Officer.

I would like to remind everybody that during this conference call, the participants may make certain forward-looking statements relating to the Company's financial condition, results of operations, plans, objectives, future performance and business. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the Company's filings with the SEC.

In addition, we may reference non-GAAP measures. Reconciliations to the comparable GAAP measures will be posted on our website. An updated Gulfport presentation was posted yesterday evening to our website in conjunction with the earnings announcement. Please review at your leisure.

At this time, I'd like to turn the call over to Tim Cutt, CEO.

Thanks, Tommy, and good morning, and thank you for joining the call. I'll begin this morning with a summary of the third quarter highlights followed by an operational update before turning the call over to Bill to discuss the financial and updates of our full year 2021 guidance.

As you saw from our earnings release, we made steady progress on numerous fronts during the quarter. We put a new credit facility in place that increases our liquidity by $160 million and accelerates our ability to return capital to shareholders, as demonstrated by the announced $100 million share repurchase program.

The six-well Angelo pad was completed in the Utica, which is currently flowing at a rate of 200 million cubic feet per day. Finally, the Company fully resolved its largest post-bankruptcy litigation exposure with TC Energy and announced the settlement agreement relating to its long-standing litigation with Stingray Pressure Pumping in September. I'm pleased to have this litigation behind us so that we can focus on the Company's tremendous opportunities moving forward.

Moving to our third quarter operational results, production averaged 973 million cubic feet of gas equivalent per day during the quarter, slightly above expectations, driven by strong reservoir performance from both the Utica and the SCOOP development programs. We anticipate an increase in total production during the fourth quarter, driven by the strong contribution from the Angelo pad.

Gulfport invested $81 million of capital in the third quarter. We continue to identify opportunities to lower our total drilling and completion costs; however, remain primarily focused on delivering peer-leading development cost per Mcfe produced.

Moving forward, we continue to target a maintenance level of capital spend of approximately $300 million per year despite service cost inflation. This level of spend is expected to result in roughly 1 Bcf equivalent per day of production, improved well performance and longer flat time periods resulting from our new development spacing, and completion designs provide this opportunity, allowing us to deliver more molecules with less capital.

Prior to providing formal 2022 guidance, we're exploring ways to improve cost efficiencies by potentially moving to a continuous one-rig drilling program in both the Utica and SCOOP.

Turning now to our development program, I'm pleased to report that our results for both the SCOOP and Utica are outperforming historical development results. On page 13 of the IR deck, you'll find recent results from our 2021 Utica program.

The Shannon and Hendershot wells have been online for approximately eight months and remained on plateau. In addition, our Morris and Gehrig pads have been online several months, and we are seeing similar promising early time data. These wells are located in the southern portion of the play in Monroe County, and we are very encouraged with how these wells are performing as compared to historic wells in the same area.

And finally, you can see the rapid build-up of the Angelo wells to their target production rates ahead of schedule. We expect the Utica 2021 development program production to stay relatively flat through November and start to decline in December as the Shannon and Hendershot wells for its line pressure. We believe that the strong performance is driven by the move to wider spacing and optimized frac jobs.

On slide 14 through 17, we have highlighted our Angelo pad development. This is our most substantial test of our new development program approach today.

We have provided a picture of the simul-frac operation on page 14 of the IR deck. This operation enabled us to complete the wells in 60 days versus 90 days using normal fracking techniques. We completed an average of just over nine stages per day versus our historical six per day and are encouraged by the fact that we achieved multiple days above 12 stages and a record day of 16.

We are very pleased to achieve 100% reuse of produced water for fracking operations and plan to utilize dual fuel rigs and frack spreads for future operations, which will lower costs and improve environmental performance.

You will see on slide 15 that we utilized two snubbing units to drill out the Angelo well simultaneously, which accelerated production startup into a high commodity price environment by 10 days. As shown on slide 16, production was brought online at target rates ahead of schedule and is expected to remain on plateau for extended period.

The estimated drilling, complete costs are consistent with our new development approach of $750 a foot. And when applying lessons learned from the Angelo pad, there's additional opportunity for improvement.

Moving to the SCOOP development results, we experienced strong production from the asset during the quarter, an increase of 12% from the second quarter. In addition, as you can see from slide 12, the wells are declining at a slower rate than budgeted, resulting in cumulative rates performing much better than historical Gulfport wells. We attributed the improved performance to wider spacing and longer laterals and are pleased with the results today. We are currently running one rig in the SCOOP and plan to run -- return to fracking operations in January of 2022.

We continue to focus on improving the Company's cost efficiency. As discussed during the last call, costs are expected to decline by $0.43 per Mcfe or 23% year-on-year, which significantly improves our margins and is expected to provide substantial and sustainable free cash flow generation moving forward.

LOE for the quarter was up slightly, primarily due to increased water hauling costs. But the full year guidance remain consistent at $0.14 per Mcfe for 2021.

Reducing corporate overhead remains a key initiative for the management team, and we have lowered recurring cash G&A guidance by $3 million compared to the midpoint of our previous guide provided in August. We expect to achieve top quartile G&A costs of $0.12 per Mcfe for the full year 2021 and maintain this run rate into 2022.

In closing, as always, we are fully committed to safely executing in the field and improving environmental, social and governance performance. We've flattened our corporate structure, reduced overhead and are focused on optimizing our development program to deliver the highest returns possible for our investors.

I'll now turn the call over to Bill to discuss our financial results and 2021 guidance.

Thank you, Tim, and good morning everyone. As Tim suggested in his remarks, we had another solid quarter, both operationally and from a financial perspective.

I will spend my time this morning providing a brief overview of our third quarter financial results, some details surrounding our recent credit facility amendment, our improved liquidity position, share repurchase authorization, and updates to our 2021 guidance, before opening our call up for Q&A.

For the three-month period ending September 30, 2021, we reported a net loss of $461 million and generated $171 million of adjusted EBITDA. Driving the net loss was a $529 million unrealized loss associated with our commodity derivatives portfolio.

Net cash provided by operating activities totaled $126 million during the quarter, and we generated free cash flow of $70 million for the same period.

To ensure our ability to fund our capital program and generate free cash flow going forward, we continue to enter into commodity derivative contracts during the quarter. For the remaining three months of 2021, we currently hold natural gas swap and collar contracts totaling approximately 800 million cubic feet per day with an average floor price of $2.65 per Mcf. We also have natural gas swap and collar contracts totaling approximately 550 million cubic feet per day at an average floor price of $2.66 for 2022 and contracts totaling approximately 65 million cubic feet per day at an average floor price of $3.39 per Mcf for 2023. Please see our Form 10-Q for additional details on our derivative portfolio.

Turning to our balance sheet, at the end of the third quarter, total assets were approximately $2.1 billion, while total gross debt was approximately $750 million, consisting of $35 million outstanding under our revolver, $165 million outstanding under our term loan and $550 million of outstanding senior notes. We also had $4 million of cash and $115 million of letters of credit outstanding at the end of the quarter.

On the liquidity front, we exited the third quarter with approximately $228 million of total liquidity, made up of the $4 million of cash and approximately $224 million of borrowing capacity under our facility.

On October 14, we announced a comprehensive amendment and restatement of our credit facility. We believe that the amendment will provide the necessary financial flexibility we need to execute our ongoing business plan. It also accelerated our ability to return capital to shareholders as evidenced by our recently announced repurchase program.

The amendment provides for, among other things, an $850 million borrowing base, a $120 million increase in aggregate elected lender commitments, from $580 million to $700 million, the repayment of the term loan under the exit facility, the elimination of the $40 million availability blocker, and a maturity extension to October 2025.

The amendment reduces the applicable rate for borrowings under the facility by 125 basis points through the elimination of the 100 basis point LIBOR floor and by decreasing the price grid by 25 basis points at each level of utilization. The new agreement requires the Company to maintain as of the last day of each quarter a net funded leverage ratio of less than or equal to 3.25 times and a current ratio of greater than or equal to 1 time.

While there are other modifications to the agreement, this should give you a good feel for some of the key items addressed. Overall, we think the amendment was an extremely positive outcome for the Company.

Pro forma for the credit facility amendment, our liquidity at September 30 increased by $160 million to approximately $388 million, comprised of the $4.5 million of cash and $384 million of available borrowing capacity under the new credit facility.

As announced in yesterday's release, the Board authorized the repurchase of up to $100 million of the Company's outstanding shares of common stock. The authorization is valid through December 31, 2022. The timing and amount of any share repurchases will be subject to available liquidity, market conditions, credit agreement restrictions, applicable legal requirements and other factors.

We intend to utilize the repurchase program opportunistically using available funds, while maintaining sufficient liquidity to execute our capital development program and to pay down debt. We believe this share repurchase program, which if executed at today's share price, would represent over 5% of our outstanding common shares, is a meaningful first step in our commitment to return capital to shareholders.

The Company will continue to evaluate all options, including potentially increasing the size of the share repurchase program and instituting a common share dividend program in future quarters. Any additional initiatives will be market and liquidity driven and largely governed by our new credit facility covenants.

Moving on to guidance, we narrowed our 2021 total production guidance to 980 million to 1,000 million cubic feet equivalent per day. Our 2021 guidance for LOE and GP&T expense remained unchanged at $0.13 to $0.15 per Mcfe and $0.92 to $0.96 per Mcfe respectively.

Our 2021 guidance for recurring G&A expense was lowered to a range of $42 million to $44 million, the midpoint of which is 17% lower compared to 2020 and is in line with top quartile performance at $0.12 per Mcfe.

Excluding acquisition and divestiture activity, our 2021 guidance for capital investment remain unchanged at $290 million to $310 million with approximately $20 million of capital associated with land and leasehold activities. A little over two-thirds of the 2021 capital budget will be allocated to the year ago.

Finally, we increased our full year 2021 free cash flow guidance by $55 million at the midpoint to a range of $345 million to $365 million at current share pricing. Please see our earnings release for a few additional details on our 2021 guidance.

In summary, we believe that our efficient asset base continues to support a low investment rate and the potential for strong return of capital to shareholders. Our 2021 free cash flow yield remains the best in our peer group, and we believe that our ability to generate significant free cash flow going forward is still largely under appreciated. Our business plan remains committed to developing our assets in a disciplined manner, investing approximately $300 million of capital to deliver roughly 1 billion cubic feet per day of equivalent production, while targeting annual free cash flow of more than $350 million at a $3.50 natural gas price.

Finally, while liquidity has improved largely due to the amended credit facility, we expect it to get even better as we execute our business plan. As stated last quarter, we believe that our ability to deliver peer-leading free cash flow provides a unique opportunity for investors. While we still plan to prioritize debt repayment in the near term, we are excited by our recently announced share repurchase program, and we're eager to share our plans for returning additional capital to shareholders in future quarters.

With that, we will now open the call up for questions.

(Operator Instructions) Neal Dingmann, Truist.

Tim, Bill, I appreciate all the early comments. I guess mine is kind of a blended question. When you talk -- think about both your growth and more particularly, maybe the shareholder return -- I guess that's more important these days for most investors -- when you think about it optically that maybe the most efficient way to run both when you think about the Utica and of course over the -- in the MidCon by -- is the plan to run one rig in each or -- I'm just wondering, I guess my question would be, how do you balance maybe running the most efficient plan again activity-wise with that which is the most efficient sort of shareholder return-wise?

Neal, that's a perfect question. I touched on it during my prepared comments. Right now, we have a program that was designed at a very low gas price, and it was designed to maximize cash flow and ultimately return to the shareholders.

With price improvement, I think it opens up opportunities to look at a more efficient development program. For instance, in both the Utica and the SCOOP, we do stop drilling for periods of time and start drilling -- start to stop fracking. And that is -- that can be quite inefficient.

And when you're in a market like we're in today, where supply costs are going up, services are hard to acquire, you build risk by doing that. So we're looking at what's the opportunity to potentially run a more consistent program.

That's part of the reason we didn't put the formal guidance out. We're going to talk about that as a Board, but obviously from an operating standpoint, our preference is to be more consistent. So I think that's a great question.

And then, it just really got right where I wanted to go, just on the follow-up. Now with the shareholder repurchase authorization, I mean, how do you sort of blend that in thinking about that -- maybe question even for Bill -- I mean, how do you think about that versus the dividend?

Yes. Neal, I'll take it first. I mean, the good news is going to a more consistent program does not cost a lot. It's probably a 20% to 25% increase in the program.

And so in the Utica, for instance, require three months. You fill that in, you stay in the same fracking schedule, you frack another pad. It's not like you're doubling up at all.

So I think you can increase and still generate substantial cash flow. And if you think about right now, $350 million is a [350] price. That number, obviously, if prices stay higher, will go higher. You still have a lot of headroom for dividend, shareholder buyback, and paying down debt, which is extremely important to take us down to at least 1 time levered.

So I think there's room for all of that. We just want to make sure we're very measured in our decision making, and we don't move to that too quickly. But I do think it's something -- it could be a positive thing.

And also, by doing that, although we wouldn't see much of an increase in 2022 on production, we could see a more substantial increase in production in 2023 if prices sustain. So I think there's plenty of room to consider this without worrying about, do we have to do one or the other. Anything to add, Bill?

Yes. I think that's exactly right; we're going to take a measured approach, and there's room. These aren't mutually exclusive. We can certainly -- again, we just did this credit facility amendment two weeks ago, basically close. So the Board and management have been in active discussions about capital return, and we'll continue to have those discussions, Neal. And we can certainly do more than one thing, and we plan on in the future.

No, I love the optionality. Thanks guys so much.

Zach Parham, JPMorgan.

I guess first off, on the Angelo pad, your well cost came in a bit below the Utica target. Could you talk a little bit about how you see well cost trending in 2022, given both cost inflation pressures, but also positive trends on the upside, including simul-frac and doing things more efficiently?

Yes. I think right now they're kind of offsetting each other. We're seeing -- obviously, everybody has different numbers they're talking about for inflation. But on any particular service or commodity, we're seeing 0% to 40% change. So on a blended basis, it may be 10% to 15% pressure.

So we're trying to basically hold our own and offset. I do think there are opportunities below the $750, but those things could get offset by inflationary effects.

We don't have a big water disposal system, for instance, in the Utica. So if we have big pads, and we're not fracking next door to use that water, it doesn't cost a lot.

So it can be a little bit lumpy. And that's why we're considering going to more consistent programs. So we are fracking more while we're producing these new pads to try and have a better place for disposal of the water through the fracking operation.

So I don't want to get ahead of our skis here as far as predicting where we'll be next year. But I do think the range around 300 if we stay with the same program is good because we are going to be able to offset some of those inflationary effects. But I wouldn't be prepared yet to kind of quote what we're thinking we'll see on dollar per foot basis yet.

Thanks for that color. Just one follow-up for me. One of your natural gas-focused peers recently announced restructuring some of their hedge book. Is this something Gulfport could potentially look at, something to do on some of your longer-dated hedges that were put in place in a very different gas price market? And maybe if you could talk about if so, what that potentially could look like?

Yes. Bill, take that.

Yes, definitely, Zach. That was another reason we did the credit facility; we needed to get some more counterparties to allow us to work on some of that. It's a little bit early to tell you exactly how that's going to play out. But it's something we're focused on, specifically the calls in 2023.

And again, next quarter, we should have a better update on that, but it's definitely something we are focused on. Now, again, part of the reason for the credit facility amendment was to allow us to address some of that.

Tarek Hamid, JPMorgan.

You certainly kept guidance online and capital sort of flat, that go-forward plan at that 1 Bcf and $300 million of capital since emergence. I guess -- and this sort of follows on Neal and Zach's questions, but given the productivity of the Angelo pad and just the broader drilling program so far this year, do you think there's upside to volumes in 2022? I guess, how do you think about your productivity assumptions on a go-forward basis?

Yes, I think, we're obviously very close. And I think the 1 Bcf is probably still a good number.

We had planned for these kind of rates. Everything we did in this year is performing about like it was expected to.

Our basic line is doing about what we expect it to do. So we're not -- we don't have much ability to accelerate things.

The permitting process in Utica is a pretty extended process. And so we don't have a lot of flexibility to bring much forward. I do think we could bring a pad earlier in the year, but that production again comes on late in the year.

So I don't think you should expect much upside. I think the lever we have is kind of how we build towards 2023. I think we have much more flexibility on how we set the stage for that. But I think most of the plans we looked at stay plus or minus around that Bcf.

I appreciate it. And just one follow-up for me, just on the timing on the execution, the share repurchase program. How (technical difficulty) do you expect to start to execute on the program? I think you should point out pretty successfully in the slide deck you're going to generate a ton of cash in 2022 and you could be out of pre-payable debt period in just a quarter or two. So I guess, how you think about timing to start chipping away on that share repurchases?

Yes. It's a good question. I mean, yes, it's obviously not in our advantage to share exactly what will be in the market. But it's something we'll be doing opportunistically.

We believe our shares are undervalued. So it's a good investment to do so. But we're not going to tip our hand necessarily, but it's something that we're definitely looking at and we're excited about.

Steven Dechert, KeyBanc.

Just one for me. I just want to see if you guys have given any consideration to raise the gas production this winter with the high prices right now?

Yes. We don't have a lot of opportunities to do that. If you look in the slide deck carefully and you look at the Shannon and Hendershot wells, those wells have been on plateau for about eight months.

About a month ago, we did turn those wells up and ran them for a while. Some of them, I think, stayed up, a few of them we dialed back. We're just trying to test what we can do without bringing basically frac sand and other formation creating operational issues for us.

And so we think we're producing these, and our target rates on the Angelo pads were 235. We're pushing that a bit. Right now, we're at 250. Obviously, with some downtime, the 235 target is what we'd stick with.

So I don't think you'll see a lot of that. What we have done and you see it in that base decline and the decline of our new wells in the SCOOP, we've been doing compression projects, we're doing a whole lot of projects on the base to get that decline flatter.

We did move as fast as we possibly could to get the Angelo pad on, came on a bit early. But I wouldn't expect that we have unlimited ability to kind of turn things out. I mean, we're going to do what we can do within kind of confines of the wells we have and making sure we continue to produce those safely. It's great having big wells, you don't want to lose one of those.

So we want to be a bit cautious on that. But again, we're trying to push that as far as we can and take advantage of the prices.

And we understand the question completely. And -- but I think the kind of guidance range we gave in the deck there is about what you should expect coming out of the fourth quarter.

At this time, we have reached the end of the question-and-answer session. Now I turn the call over to Tim Cutt for closing remarks.

All right. Thanks very much. And thanks for calling in and asking the questions and also calling in to listen, we appreciate that. I mainly want to say once again, thanks to our organization, our employees, our contractors, who actually did a lot since the beginning of this year, and you've delivered against that well, and we do appreciate that a lot.

Again, appreciate your time today to join in. And if you have any additional questions, don't hesitate to call Tommy and reach out to our Investor Relations team. But with that, that concludes the call. Thank you.