Riley Exploration Permian Inc (REPX) 2022 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Brent and I will be your conference operator today. At this time I would like to welcome everyone to Riley Permian's Q2 2022 earnings call. All lines have been placed on mute to prevent any background noise. (Operator Instructions). It is now my pleasure to turn today's call over to Mr. Philip Riley, Chief Financial Officer. Please go ahead.

Thank you and good morning to everyone. Welcome to our fiscal second quarter 2022 conference call covering the three-month period ending March 31, 2022. Today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties t5hat may cause actual results to differ materially from those expressed or implied in these statements.

We will also reference certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. Additional information on the risk factors that could cause results to differ -- available in the company's SEC filings. A full cautionary statement about forward-looking commentary can be found in our earnings release.

In addition to our earnings release, we published an updated presentation available on our website. Participating on the call today are Bobby Riley, Chairman and CEO; Kevin Riley, President; and myself, Philip Riley, CFO and EVP of Strategy. I will now turn the call over to Bobby.

Thank you, Philip. Good morning and thank you for joining us today on our fiscal second-quarter call. In a world already impacted by supply chain issues, the actions taken by Russia in February have further exasperated the situation not just in the Permian basin but globally. Inflationary cost pressures have continued to build in the labor, materials and equipment markets as we have seen oil prices increase 82% year-over-year.

I'm happy to announce the company has been proactive in securing a drilling rig and casing for 100% of our fiscal 2022 development activity and for up to 14 wells already planned for fiscal year 2023. We are halfway through our fiscal year and continue to have operating and financial results exceeding both guidance and consensus expectations.

To highlight a few items for fiscal second quarter: average oil production of 7,500 barrels per day which is at the high-end of guidance. We generated $34 million of adjusted EBITDAX in fiscal second quarter. We paid dividends of $0.31 per share for a total of $6 million. Estimated proved reserves of PV-10 of 1.1 billion as of March 31, 2022, based on NYMEX pricing.

As we turn to the second half of our fiscal year, we are excited to announce increasing guidance for fiscal third quarter and fiscal year 2022 production volumes, along with other corporate initiatives starting to materialize. We've also continued to add to our staff, including the addition of an experienced carbon capture and enhanced oil recovery technical team, which is timely considering the progress at our EOR pilot project.

Lastly, before turning it over to Kevin to discuss operating results, subsequent to quarter end, the company amended our credit facility to extend the maturity to April 2026, while additionally increasing our borrowing base by 14% to $200 million and relaxing minimum hedging requirements when the company is less levered. We view this as continued confidence from our syndicate of lenders and our business plan and assets. I will now turn the call over to Kevin to discuss operational results.

Thank you, Bobby, and good morning to everyone. As Bobby mentioned, we had a great quarter and first half of our fiscal year. Riley Permian averaged daily oil production of 7,497 barrels for the quarter, which is a 3% quarter-over-quarter growth, or 24% year-over-year growth as compared to the fiscal second quarter of 2021.

The company averaged total equivalent production of 9,791 barrels of oil equivalent per day for the same period, which is a 2% quarter-over-quarter decrease or 18% year-over-year increase as compared to the fiscal second quarter of 2021.

As previously disclosed, the gas and NGL sales during February through early May have been impacted from expansion underway at our midstream partner's facilities. The expansion remains on schedule and, once completed, the plant will provide additional takeaway capacity to our operations, which will further reduce flaring of natural gas and is expected to increase sales volumes.

Though our production on an equivalent basis decreased quarter-over-quarter, we did see oil production continue to grow. The company continued its efforts on its fiscal year 2022 development activity, including the drilling and completing of 3 gross, 3 net horizontal wells, which have all subsequently started producing past the close of the quarter.

We turned 2 gross and 1.7 net horizontal wells onto production and we commenced predatory activity for 3 gross, 3 net horizontal wells to be drilled and/or completed during the fiscal third quarter. The activity above corresponds with 23.8 million in accrual basis drilling, completion and facility capital expenditures, which also includes capitalized workovers, midstream infrastructure, and minor additions to land and working interest.

The company advanced its EOR pilot project in Yoakum County, Texas, completing 1 of the 6 newly drilled injection wells and [installation] of the high-pressure injection lines for both water and CO2. The activity corresponds with $1.5 million of accrual basis CapEx. Subsequent to the quarter end, the company began water injection on the EOR pilot program in early April 2022.

On the capital cost side, we estimate drilling and completion costs for recently completed wells are averaging 16% higher than an equivalent well design from a year ago, owing to some inflationary pressure, but partially offset for some efficiencies we are seeing. Lease operating costs were $6.8 million or $7.75 per Boe for the three months ended March 31. This came in at the low end of guidance, which was partially impacted by lower workover activity due to limited workover rig availability.

We anticipate higher lease operating costs in the fiscal third quarter as we catch up on the delayed remedial work from the second quarter along with the normal anticipated activity. I will now turn the call over to Philip Riley for a review of our financial results.

Thank you, Kevin. Today I'll discuss four primary topics: summary financial metrics; pricing and differentials; hedging; and capital allocation. First a few summary financial metrics. We performed well across the board with production at the high-end of guidance, cost at the low end of guidance, and CapEx within guidance.

We're reporting a net loss for the quarter of $7 million driven by a $49.6 million loss on derivatives, which includes $18 million of realized derivative settlements and $32 million of unrealized loss, owing to changes in future strip pricing as of 3/31. If we reran the numbers today that loss would be lower. For the six-month period we're reporting net income of $14 million with operating income of $74 million.

Our cash margin per Boe increased 28% quarter-over-quarter to $59 per Boe before derivatives. After derivatives cash margin increased 34% quarter-over-quarter to $38. Relative to other industries our business is fortunate to participate in dramatically increasing topline prices. Rising costs represent a headwind, but one that is not unique to us, and which we are able -- also actively manage and for which we believe we are well positioned as an inflationary hedge.

Adjusted EBITDAX was $34.4 million for the quarter or $61.5 million for our first six months of 2022. Simply annualizing that the six-month figure would correspond to $123 million. And we see potential to exceed that as the roll off of our hedge position could more than offset the backwardation in pricing for the remaining five months to go in our fiscal year. Of course results will depend on ultimate pricing and performance.

Operating cash flow for the quarter was $30 million and free cash flow was $20 million. And if you consider the negative $18 million of hedging settlements, or ignore them hypothetically for future run rate periods when we're less hedged, you can appreciate an idea of potential cash generation.

Next I'll offer some additional color on pricing, basis differentials and commodity fee deducts as this can be a bit confusing for some observers. Quarter-over-quarter our realized oil price improved 22% to $92.44, representing a slight positive basis differential to WTI for the quarter. We often experience modest discounts or small premiums relative to other Permian barrels as refiners in our area like our slightly heavier, slightly sour barrel to mix with the very light barrels coming out of the Delaware and Midland basin.

Adding in realized hedge losses of approximately $26 per barrel, our net realized price after derivatives was $66.60, 23% higher than the prior quarter. This was driven by a combination of higher market prices and lower hedging volumes.

For natural gas, our net realized price declined by 18% quarter-over-quarter. Index price was [$4.66], about $0.10 lower than last quarter. Basis dif was about negative $0.52, a higher deduct than the prior quarter but not dissimilar to past quarters. Our gas is generally shipped north and west, experiencing less congestion than far south and Waha or EP Permian and, in turn, generally less discount to Henry Hub. Our processing fees are about $1.50 leading to a net of $2.62 before derivatives and $1.25 after derivatives.

For NGLs, the market price for a composite barrel garnered $44 this quarter, which is about $4 less than the prior quarter. Many industry observers apply shortcuts in estimating an NGL price relative to WTI. And I'd just note that last quarter was probably an aberration at 62% of WTI, with this quarter being closer to the norm at 46%, but still higher than levels experienced last year.

Then our NGL gathering processing fees this quarter were approximately $17 per barrel, about $0.30 higher than last year, yielding the net $26.71 you see on the financials. This fee will likely be more flat than floating to WTI, and we have no hedging against NGLs.

So, moving on to hedging -- as discussed previously, our hedge strategy has evolved which, among other reasons, include decreased leverage, changing supply and demand fundamentals, and steep backwardation in pricing markets. And with the amendment to our credit facility achieved a few weeks ago, which allows for a lower minimum level of hedging, we have greater discretion in the decision-making.

Our hedging objectives are balanced with an effort to maximize upside exposure, to maintain flexibility to react to changing environments, and to manage risk for very low prices. We are not seeking to lock in perceived good prices.

And with cash costs of $16 per Boe, which, by the way, includes $4 of production taxes tied to commodity prices, we can cover cash operating costs at very low commodity prices. We've made no change to our hedge position since last quarter, other than the roll off, as we've faced no new requirements in response to the credit facility amendment.

Slide 15 in our presentation is updated for increased forecasted production with an estimate that we're approximately 57% hedged for the remainder of fiscal 2022, or just under 30% hedged for fiscal 2023.

Moving on to cash flow and capital allocation. Total change in cash this quarter was $11 million, the components of which include $30 million of cash flow from operations offset by $10 million for investing activity and $8.5 million for financing activities, the latter reflecting a $2 million net payment on our credit facility at $6 million of dividends. Free cash flow was $20 million. Free cash flow will fluctuate in tandem with our development pace, which includes on-and-off periods of activity.

Cash balance at quarter end was just under $20 million with $63 million on the credit facility, which was nearly 70% undrawn based on the new $200 million borrowing base for the amended credit facility. That corresponds to over $150 million of liquidity inclusive of revolver availability.

We have the same revolver balance today which has the potential to rise modestly these next six weeks as we work our way through some of last quarter's accrued CapEx with continued active development. That's not a given but certainly a possibility. For the subsequent quarter we currently see opportunity to reduce the balance, at least based on current activity, pricing, and capital allocation. Though we generally see benefits to maintaining a higher cash balance given volatility, larger swings in revenue receipts for hedging payments, etc.

Okay, a few thoughts on capital allocation looking forward. At the core for an E&P company, cash allocation choices primarily include: reinvesting to offset natural production clients and/or to grow further; investing in new assets or new ventures; paying down debt if applicable; and returning capital to shareholders in one form or another.

Many larger E&Ps believe they have less optionality for production growth in today's environment given pressures from investors to directly return large amounts of capital, which is understandable following poor returns last cycle and/or fears about meaningfully adding to supply and disrupting the global balance. We understand and respect these positions.

At Riley Permian, however, we believe we can and should allocate more capital to growth as a smaller company. As Bobby previewed and our written materials outlined, we're choosing to increase activity and production this year. Riley Permian is and always has been a growth story. We've been growing an average of 20% per year for the last several years. We grew at those levels when oil was $50 and lower. We'll certainly pursue that growth at $70 or $90 oil.

The great thing is we see lots of room to grow further but to keep spending well within cash flow at current pricing and lower. Very simply, we see underappreciated value in our undeveloped assets. We see the benefit to convert the undeveloped to producing cash flow. Investors seem to be valuing companies primarily off of near-term measurable EBITDA or free cash flow, not acreage and PUD value, or not forecasted EBITDA even 18 months out.

We can appreciate this conservative mentality given the volatility and uncertainty present. But we're ready to get on with it and to bring some of that forward. Our management team, Board and many of our investors with whom we've spoken to believe this represents the best near-term approach to equity value creation. We appreciate your ongoing support and we're excited about what's to come. Thank you and I'll turn it back to Kevin now.

Thank you, Philip. I will now give guidance for the company's activity for fiscal Q3 2022. The company forecast [yielding] 5 gross, 5 net, completing 4 gross, 4 net and turning to production 6 gross, 6 net horizontal wells during the fiscal third quarter of 2022. Of the 6 gross, 6 net wells being turned to production, 2 gross, 2 net are wells that were in preliminary stages of flow back at the end of the fiscal second quarter.

We anticipate accrued non-EOR-related capital expenditures before acquisitions to total approximately $25 million to $28 million. The company forecasts fiscal third-quarter 2022 oil production to average 7,600 to 8,100 barrels per day with the midpoint average representing 5% quarter-over-quarter growth. The company forecasts 10 to 10.8 MBoe per day for the fiscal third quarter as well.

The midstream expansion project is expected to be fully commissioned in early June. But due to some curtailment during April and May, the sales of natural gas and NGLs during the fiscal third quarter will be impacted. Following the completion of the expansion the company will enjoy a larger volume of contractual firm capacity which should lead to increased sales for gas and natural gas liquids along with reduced flaring.

As discussed earlier, we do anticipate higher lease operating costs of between $8 million to $10 million in the current quarter, partially due to the delay of certain workovers in the second fiscal quarter. As previously stated, we are giving this on an absolute basis versus on a per Boe basis due to the uncertainty on curtailment volumes due to the expansion of our midstream partners' gas gathering processing facilities.

For cash G&A we anticipate $3.7 million to $4.7 million. The company will continue to advance its EOR pilot project in the third fiscal quarter completing additional injection wells and making progress with the CO2 tap and infrastructure installation. Management anticipates $3 million to $5 million of accrual basis CapEx for the EOR program during the fiscal third quarter.

Based on anticipated delivery times and the compressors needed for CO2 injection, the company now forecasts beginning the CO2 injection during calendar fourth quarter 2022. Based on current market conditions the company has elected to add 3 gross 3 net wells during the second half of fiscal 2022.

The drilling of these wells is scheduled to begin in the fiscal third quarter with completion scheduled to occur in the fourth fiscal quarter, therefore we anticipate incurring the capital expenditures for the additions in fiscal 2022 while production from the additional wells captured within fiscal 2022 will be modest.

We anticipate our full-year fiscal 2022 accrued capital expenditures to total approximately $102 million to $111 million. This includes $84 million to $89 million for drilling and completions, capitalized workovers, infrastructure and minor additions to land, and $18 million to $22 million for our EOR program.

Based on our current estimates and availability, we forecast full-year fiscal 2022 oil production could average 7,500 to 7,800 barrels per day, representing 17% to 22% growth from fiscal 2021 average oil production. In addition, we forecast full-year fiscal 2022 total equipment production could average 10,000 to 10,400 of oil equivalent per day. I will now turn the call over to Bobby for closing remarks.

Thank you, Kevin. And again, thank you to everyone for joining us today for our second fiscal quarter call. We are very pleased with our year-to-date results and remain excited about the continued forecasted growth.

As we look forward our team is taking several steps to navigate through inflationary pressure for services and products. We remain focused on a disciplined model of low leverage production growth and return of capital through dividends to our shareholders. Thank you again for your support. Operator, you may now open it up for questions.

(Operator Instructions). Neal Dingmann, Truist Securities.

Good morning, all. Thanks for the details. A couple just to go through. Kevin, can (inaudible) -- or I guess one of the guys really, just walk through the growth? Is that just expectation now? Great to hear that planning for a bit more growth. Is that just assuming the (inaudible) stay for the better part of the year or what's sort of the new expectation for that? Is that just a constant program now?

We have not gone into a continuous development program yet. But the rig that we have currently will stay through mid-May and we will drill one additional well in early July and look to pick back up the program either September or October.

Okay. And then I guess that kind of leads me to my next question. Kevin, can you talk a bit about just the confidence that, one, you'll be able to take that rig out? And then the basis of my question is just logistics in general. There's obviously a lot of tightness out there. And I guess my question is for kind of in your area versus in the heart of the Permian where some of the bigger equipment is.

Do you have the same kind of constraints as the others, and so I guess the confidence to get the rig -- to get those workovers that you mentioned were a bit delayed? And then separately could you talk about the takeaway constraints. I think the last call -- I think you were thinking it would be April and so now it sounds like it's delayed a little bit more. So, if you could just maybe talk about logistics between the services and then the pipe.

No problem. So, on rigs and pipe, as we mentioned in the call, we have it secured for 100% of the activity planned for within fiscal year 2022. We've already secured both rig and pipe for us at 14 wells for our fiscal year 2023, which will be a large portion of what we do at least in the first half of the year.

Other services, we are still competing for completions, frac sand, etc. But we do have good relations with multiple parties that we continue to be able to get on their schedule and we're looking forward into 2023 to get that secured as well. I guess your second question was -- repeat it again.

Just on the pipeline. I think you said that it could grow (multiple speakers).

It's truly on target. I think the date was anticipated to be mid-May for it to come back online. But it was going to be -- there's some curtailment between early February and I believe it was mid-April. And that did take place, so we reduced our amount of gas that we were selling from January before through that period.

They had a shut down for seven or eight days at the end of April, a complete shutdown as they plumbed in the expansion equipment. So, that has come back online and we're currently producing and have been producing since May 1 back to the capacity which we were producing in February and March. And we do anticipate, as they continue to commission the compressors on the new expansion, that production volumes or inlet volumes will continue to increase through the end of May and into early June. We'll be at our full capacity at that point.

Great to hear. And then last two quick if I could. Just EOR, you guys -- it sounds like that's (inaudible) and all, can you just talk about maybe (inaudible) in time when you would start having water potentially in all those injection wells? Is that still in the next few weeks or next coming weeks or so?

I would say we'll continue to be bringing additional injection wells on for the remainder of this quarter. Whether or not we have them all on by June 30 or July 31, I'm not sure. I think we'll have then by the latter at minimum.

But we have started the completion process in the last couple weeks and we've been running cased hole logs to identify our perforations, etc., and the rigs are beginning to free up to move out there. We do use a lot of the same rigs for our workovers and for our drill outs on our own completions, so just trying to manage personnel and equipment as we see prudent.

No, good to hear. And then lastly just maybe, Bobby, for you or Phil, just on the CCUS. Great to hear you've hired somebody. Do talks continue or just what more can you say on that given obviously the exciting potential there?

This is Bobby. We did hire the team that came from the CO2 industry. We're just kind of ramping up where our opportunities are, specifically looking at one or two. But they're also in there to also optimize CO2 injection in the wells and how we get the most efficient sweep out of the thing.

But I would say overall we're doing what we can at the moment. We're still waiting on Kinder Morgan to get the [tap] finished. We will inject some gas primarily, but hopefully with the next say six to 12 months we might have something firm in place that looks like a potential source.

John White, ROTH.

Good morning, gentlemen, and congratulations on nice results. I'm sure everyone appreciates the increased production guide. Again, on the CO2 and CCUS team, how large is the team? And would you characterize their skill set as being more concentrated on CO2 or [CCS]?

Well, I would say, based upon the history of CCUS actually capturing flue gas and stuff in our areas, it's relatively new. But these guys did come from a major CO2 pipeline company that know where we're going to be able to access the line, how we're going to be able to access the line. And again, the initial team is three individuals that we brought on, be focusing out of North Houston. So, I mean -- John, it shows our dedication and commitment for sure.

Well, great. Actually I'll be in Houston, I can run out and see them maybe.

Noel Parks, Tuohy Brothers.

Hi, good morning. Just a few things I wanted to check in on. I was looking at the list on the EOR CapEx. I just wondered, was most of that set in motion before this most recent wave of inflation kicked in? Or are any of the components of that going to be seeing some inflation?

I'd say a large portion of it from when we started the project in September or October has been secured from the drilling of the six wells, so all your steel casing in addition to the injection lines have all been acquired. So, those prices still are higher in that period than call it 12 months earlier. They're not seeing the same inflationary pressure that we're seeing today in the market.

So, I think like everything, the services are still going to be having some exposure. But the things that we contracted and did in the first half of the year have less exposure. So, we still feel comfortable within that capital guidance that we've given for this (multiple speakers).

Great, thanks. And just for some perspective -- on the Northwest shelf, how many industry rigs are active right now would you say?

Last time I looked I think I saw four rigs currently running within the Yoakum County area.

Okay. Okay, great. And I was curious about the business development team and what they're seeing. Curious about what the thought processes of people talking about selling and whether that's largely just price driven, they have a higher for longer hope or expectation and they're saying this is the time? Or is there anyone who comes to the table because of last capital or issues like that?

Yes, no, this is Philip, I can try to take that. I'd say on the marketed processes we've certainly seen a lot of those these first five months of the year. Whether that's due to $100 oil or not the statistics are there, there's a lot of deals being marketed on the broadly auctioned processes. We tend to look at more conventional assets than the [shale], but I think there's clearly a lot of people out there that have been holding onto things for a long time that maybe were uneconomic at lower prices and now look better, and you can't blame them for that.

As for their other rationale as to why to sell, I don't know whether they think prices are here for longer or not, but some of those are owned by sponsors, some of them maybe were the unnatural owners push [real] creditors and such that finally need to monetize that. We've seen a mix of buyers come -- the larger privates that have some access to capital, guys that are willing to lean in on assumed operating cost improvement, LOE cost improvement and such. So, you see a mix out there.

We certainly see some deals that are harder to get done, the type to have maybe a larger P&A obligation. There's always a bit of concern about how to manage that, especially with the current administration. So, as far as our perspective on it, we are opportunistically looking. We recognize the benefits of scale and what that could do for our business and our shareholders. At the same time, we're mindful of where prices are now relative to the last 10 years. We're mindful of backwardation and we're just looking for the right balance.

We are interested in deals where we could use equity. Those represent, obviously, an attraction more so than just using debt. But we're also mindful of dilution. So, that's a lot of words there, but I'd just say we're trying to be mindful and finding just the right Goldilocks type of deal for us.

Fair enough. Great. And I'm just thinking about the leases in general. Is there much out there in the way of people facing acreage expirations? I'm trying to think back as to when the most recent waves of leasing occurred and thinking, okay, three years or five years later. So, is that the case or is pretty much everything held by production that's of interest to you?

On the A&D front, again, we focus less in the super crowded sandbox of the Midland and Delaware basins. To make a quick comment there, we're less familiar, but what we have seen from afar is that the big companies try to manage that with their drilling programs to hole it with the rig versus releasing when they can't. There's generally an efficient market that will solve for that constraint.

I think there's a lot of private equity type players that don't mind the smaller scale one-off blocks and such, kind of the low down strategy where you can buy single units and just complete 6 to 8 wells within it and underwrite it for cash flow. So, I think that market exists. In our area we don't see that type of pressure with the acreage expiring. We would certainly chase some if we could.

Most of the people in our area have theirs under control. We certainly make an active effort to manage ours and hold it with the drill bit, to be mindful and efficient with our dollars versus releasing. There's always a very small working interest and such here and there that we have to allocate capital to. But as you can see from our financials it's usually pretty small.

Great. And just the last one from me, I was trying to recall as far as when you start flowing CO2, is your purchase price for the CO2 tied to oil price? I'm just trying to recall if that was the nature of the contract?

Yes, it is, it is an index tied to oil price.

And how often, how frequently do you adjust that, like a monthly thing, a quarterly thing?

No, it's percentage based, it's got a flat floor, but at today's prices the percentage is going to be more applicable.

Okay, great. Thanks a lot.

(Operator Instructions). Jeff Robertson, Water Tower Research.

A question on your EOR project. I believe you said you had six injection wells. Is that one pattern or more than one pattern? And can you talk a little bit about the timeline to when you expect the field to actually start responding to injection?

So, basically since we have six injection wells placed between three horizontals, it's not what you would consider your typical [five spot] pattern in vertical completions. So, this is really -- in reality it's more like half a pattern. But due to the nature of the way the wells are completed and the vertical injection wells, we feel like we're going to get a pretty efficient sweep that way.

Typically within I would say three to six months of start of injection you start seeing some response and some CO2 bleeding through that you recycle and re-inject. But obviously it's probably for full -- full effect is probably closer to a year before it's completely efficient.

Will you monitor -- I guess you will monitor the performance of this pilot before determining where else to go in the field.

That's correct and that's why we call it the pilot -- part of the infrastructure we are putting in place allows us to easily expand the patterns with additional vertical wells. And we're actually analyzing the potential of even a horizontal injection well in the future.

And then lastly, can you talk about how you'll be able to book reserves based on the performance of the pilot?

Obviously there's an established method on CO2 response and expected type curves or expected response. And we'll be looking at our response compared to those projections. And then obviously the engineering companies that we use like (inaudible) can imply what that curve is going to look like with the effect of CO2, primarily flattening of the curve with a potential early bump in production.

So, that would start to impact fiscal 2023 reserve reporting? Is that right?

I would think that fiscal 2023 is basically October 1. So, yes, it would probably be the end of first quarter before we start seeing some booking of reserves.

Okay. Last question, can you capitalize the cost associated with injection until you start to see response in the field?

Yes, that's what we're doing.

Okay. Okay, thank you very much.

There are no further questions at this time. Ladies and gentlemen, thank you for your participation. This concludes today's conference call. You may now disconnect.