REPX (2022 - Q1)

Good morning. My name is David and I will be your conference operator today. At this time, I would like to welcome everyone to Riley Permian Fiscal 1Q '22 Earnings Call. Today's conference is being recorded. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. Thank you. Philip Riley, CFO. You may begin your conference. Philip R

Thank you and good morning to everyone. Welcome to our first fiscal quarter 2022 conference call covering the three month period ending December 31, 2021. As a reminder, 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 that may cause actual results to differ materially from those expressed or implied in these statements. We will also be referencing certain non-GAAP measures. These 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 is available in the company’s SEC filings. The full cautionary statement about forward-looking commentary can be found in our earnings release. Participating on the call today are Bobby Riley, Riley’s Chairman and CEO; Kevin Riley, Riley’s President; 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 the call. Riley Permian completed another strong fiscal quarter with continued growth across operating and financial metrics. We grew production above guidance and have provided guidance for continued growth this coming quarter. We realized improved pricing across all commodities, which was partially offset by realized hedging losses and some higher LOE, but overall margins improved from the prior quarter and year. On the cost side, we're experiencing some inflation in selected areas, which Kevin will elaborate on further in which we're of course monitor closely for overall impacts to our business. We work to manage our hedge profile and overhang, which we hope is getting better each coming quarter, and which Philip will discuss in his prepared remarks. So management of our cost structure and supported market prices generally around the level we've seen over the past few quarters provides us with a potential to see materially higher margins in the coming quarters. We made significant progress during the quarter on our EOR pilot project, in which we collected our permits, drilled our injection wells and installed the majority of our pipeline infrastructure. We plan to begin water injection in the fiscal second quarter with CO2 injection scheduled to begin later in the summer. Carbon capture projects remain a priority for our team where we're having good engagement, navigating the various requirements to make a good project. We continue to return capital to shareholders in the form of dividends, which we paid during the first fiscal quarter and which were paid last week. Finally, at our board level, we were excited to welcome Rebecca Bayless to our Board of Directors in January. Becky brings extensive operational and management experience in all facets of the energy industry, as well as a 25-year track record with successful energy companies. We welcome her vision and viewpoint on our board as we continue to build and scale Riley Permian. I will now turn the call over to Kevin Riley to review operational results.

Thank you, Bobby and good morning to everyone. I plan to review operational results for the first quarter ended December 31, 2021. The company brought online five gross, four net horizontal wells during the first quarter investing a total CapEx of $20.7 million of which approximately 70% was invested in non EOR drilling and completions activities and 30% towards our EOR pilot. We drilled four operated and one non-operated wells in our champion area of the Northwest shelf. For the operated wells, we averaged 11 days per well from spud to rig release with an average total measured depth of 12,873 feet and completed lateral length of 7,035 feet. On the capital cost side, those still early, we think drill in completion costs for the recently completed wells are averaging approximately 6% to 8% higher than an equivalent well designed from a year ago, owing to some inflationary pressure, but partially offset for some efficiencies we were seeing. During the first fiscal quarter, we realized the delay due to rig availability associated with one gross 0.66 net wells we had planned. This well is now underway with completions expected before the end of our second fiscal quarter. There might be small delays, we increased oil production to 7.3,000 barrels per day, which is a 5% quarter over quarter growth or 22% year over year growth for the three month period. Total net equivalent production was 9.9,000 barrels of equivalent per day, which is a 4% quarter over quarter growth or 31% year over year growth with the later metric being higher than the oil growth due to expanded gas processing capacity. So the rig delay mentioned should not materially impact our full year production either and guidance remains unchanged from what was previously announced. Lease operating costs were 8% higher than our midpoint guidance coming in at $8.11 per Boe for the three months end of December 31, 2021. The increase in lease operating costs was largely driven by our non-recurring work over cost of $1.1 million or a $1.30 per Boe associated with three operated disposal wells. These workovers included the replacement of the injection tubing on each of the wells. So as anticipated last quarter's LoE in the mid-$6 range was unusually low. This quarter's $8 per Boe level is about 16% higher than last year's average and identical with our 2020 average. Excluding workovers, the base LoE was about 6% higher than last year's average. This is reasonable given the inflationary environment we're in. We're starting to see price increase on various other items, including electricity and production chemicals, which make up the largest portion of our recurring lease operating expense. Though the lease operating cost increase for this quarter, we expect future lease operating costs to fall more in line with our forecasted cost over a longer period barring continued unusual workover activity in rampant inflation. As previously disclosed in our fiscal year 2021 earnings release, the company has continued to progress on its EoR pilot program. The company has drilled six of six currently planned vertical injection wells and has completed installation of water and CO2 injection lines, which are now being pressure tested. We anticipate being able to initiate water injection for the project as early as March 2022, which will continue into the reservoir is sufficiently repressurized and the Co2 tap has been installed in the summer of 2022. At this point, I'll now turn the call over to Philip Riley for the reviewer financial results.

Thank you, Kevin. Similar to past formats, I limit stating all the standard financial results and instead highlight select metrics with commentary on a few focus areas. For the fourth quarter, we're reporting net income of $21 million, which includes operating income of approximately $33 million. We had adjusted EBITDAX of $27.1 million for the quarter or approximately $97 million for the 12 month period ending December 31. Comparing to our prior quarter ending 9/30/21, this represents an increase of 11% or $2.6 million. Approximately $2 million of that increase is driven by increased volumes. Higher commodity prices drove revenues up by $6.5 million, excluding the impact from volumes, but offset by $4.8 million of larger realized hedge losses, then production taxes, LoE and overhead combined for a net $1 million increase approximately. Oil sales are clearly the driver for our revenue, but I want to first come and on gas and NGLs as they are growing contributors of revenue and the differentials to index pricing can cause confusion for some investors. During the quarter ended December 31, 2020, more than a year ago, we had $300,000 in combined gas and NGL revenue. This immediately past quarter, we had $6 million, about 11% of overall revenues. Gas and NGL volumes have increased disproportionately higher than oil due to increased processing capacity, which also means less flared gas, but the real driver in the revenue increase is higher prices. Year over year, our realized gas price is up nearly $3 similar to the reporting methodology of many EMP companies, we net out gathering and processing fees of our realized pricing, which have approximated a $1.70 over the past two years. So the business really starts to have operating leverage for amounts above and beyond the fees as we get into the $3 and $4 index pricing level. A similar dynamic on a better realized pricing occurs with NGLs, where we were well clear of the fees leading to realized pricing being up 65% quarter over quarter, or well over a 1,000% year over year and with realized pricing at about 40% of WTI versus teens or twenties last year and 6% one year ago. For gas and NGL hedges, about two thirds of gas volumes were hedged for the quarter ended December 31. For calendar year 2022, we have similar hedge volumes at an average price of $3.26.. We have zero NGL hedges. So we've been enjoy a full price appreciation there. Moving on to oil pricing and hedges; for the quarter, our realized price improved about 10% to $75.67 cents, which was largely offset by realized hedge losses above our $21 per barrel for net realized price after derivatives of just over $54, about 3% higher than the prior quarter. You'll see $5 million hedge losses on the income statement, whereas if you look at the disaggregated detail in our 10-Q, you'll see that includes an approximate $11 million unrealized gain offset by $16 million and realized hedge losses. The unrealized gain was essentially a sharp downward swing and pricing we saw during November and December relative to the higher pricing and president quarter, which made the hedges less out of the money. As pricing has once again shifted higher, after quarter end you can expect the unrealized dynamic to reverse. We recognized we've been significantly hedged on oil production. For the last four quarters, we sold 2.46 million net barrels and had 2.14 million hedged over 85% in the low fifties. Based on current market conditions and assuming our leverage level stayed low, we plan to be less hedged overall relative to the past with relatively higher amounts of hedging for production forecasted within a rolling 12 month basis and less hedging beyond 12 months, which may allow for more flexibility to react to market conditions as well as hedge price optimization in a backwardated market. So our hedge book may still weigh on our bottom line cash flow this fiscal year, but we see that improving starting in the current quarter with lower hedge volumes and assuming market prices are directionally consistent with recent pasts. We're hoping 2022 marks a good transitional year on realized pricing. Based on positions as of today, our oil price hedges are dropping 123,000 barrels or 22% in this fiscal second quarter compared to the fiscal force quarter. So if you look at only these unhedged barrels and apply current market pricing, which is averaged in the mid-80s halfway through this quarter, more than $30 higher than our weighted average hedge price in just the prior quarter, then unhedged volume has the potential to yield $3 million to $3.5 million in incremental net revenue. For the oil hedges we do have, the weighted average price is about $3 higher this quarter than the prior quarter's price, which could itself yield more than a million dollars in incremental hedge realizations, and none of this accounts for any production of growth, which would be applied to market pricing. And then looking a bit further out, the quarter ended September 30, 2022 currently has hedge volumes about 30% or, and with a weighted average price over $6 higher than this past completed quarter. I offer these anecdotes that you can start to piece together our potential for real step up and cashflow in the coming quarters. All right, moving on to some operating costs and margins for the quarter, Kevin discussed LoE. So I won't discuss that. Normal course administrative expenses decreased by over $1 million from the prior quarter. We refer to cash G&A expense, which is a non-GAAP measure and one that we define as excluding share-based compensation and benefiting from the effect of revenues from contract services, cash G&A for the quarter was $3.2 million or about $3.50 per Boe's production, about 20% below midpoint guidance. This category will continue to fluctuate and we're guiding to a higher figure again, as we see some seasonality with certain costs, higher possible costs with professional services, business development, activities and insurance among others. Our cash operating margin on a per Boe basis improved about 7% quarter over quarter for mid-$26 to mid $28. We show this non-GAAP metric in the back of our earnings release, which includes just under $62 per Boe of pre-hedged revenue, $17.51 per Boe of realized hedging loss and just under $16 per Boe of cash costs, which includes all operating costs, production and ad valorem taxes, cash G&A and interest expense. The LOE by itself was just above $8 per Boe. Moving on cash and cash flow allocation; cash flow from operations for the quarter was $21.7 million, including $25 million before changes in working capital and then a little over $3 million of negative changes in working capital. On CapEx for the fiscal first quarter, the company had $20 million in accrual based drilling completions and facility capital expenditures, $6.3 million of which relates to our EOR project. Including additions to leasehold and other property and equipment, company had $20.7 million in total accrued capital expenditures for the three months ended December 31, 2021, which compares to the company's previously released guidance of $26 million to $32 million. The lower anticipated accrued CapEx can be attributed to development activity timing differences, falling outside of the quarter. On a cash basis, the company had total CapEx before acquisitions of $29.1 million for the three months into December 31, 2021. The difference here versus the accrued figure includes amounts for quarter activity that has a lag effect with the cash payment. If you use this quarter's cash flow from operations and this higher cash CapEx figure that leads to negative free cash flow for the quarter, which we anticipated giving timing of our development spending. Further in managing the operations of the company we're more focused on efficiencies and cost savings, which may lead to concentrated capital spending in some quarters rather than ensuring that each quarter yields positive free cash flow. For the full year 2022, we do forecast creating significant free cash flow. Our allocation of CapEx relative to cash flow from operations will likely appear higher than fiscal 2021, given the incremental spending on the EOR special project falling within this fiscal year. We'll also point out the EOR pilot program represents a special project outside of the normal self-funding operations and one for which we raised equity capital last summer. Total change in cash this quarter was negative $8.8 million, including $21.7 million of cash flow from operations offset by $29.1 million for the investing activity and $1.3 for financing activities, reflecting a $5 million draw on our credit facility offset by our $6 million dividend payout. We ended the quarter at $65 million on the credit facility. Subsequently during February, we drew an additional $3 million with $68 million outstanding currently. These draw amounts aligned with our forecast and we believe this may represent approximate peak borrowing for the year with anticipated paydown through the year, given a lighter capital spend in the back half of the year subject to market conditions of course, and swings in working capital. Final point I'd make on cash and debt is that our quarter end cash balances have the potential to be deceptive with our commodity sales receipts typically arriving just before quarter end, while hedge settlements, which have been largely negative for us of late occur at the beginning of the following month. The combined effects may be helpful in understanding our reported cash balances. I'll now turn it back to Kevin to discuss our forward guidance.

Thank you, Philip. I'll now give guidance for the company's activity for fiscal quarter two 2022. We're forecasting fiscal second quarter 2022 accrued capital expenditures before acquisitions to total approximately $26 million to $32 million. This total includes an estimated $20 million to $24 million for normal course drilling and completions, both operated and anticipated non-operated, capital work-overs, infrastructure, then minor additions to land and existing working interest. Then we estimate another $6 million to $8 million for our EOR program. Consistent with prior quarter, we forecast a larger weighing of capital spending during the first half of fiscal 2022 in line with guidance previously provided and based on current marketing conditions and cost, we still anticipate full fiscal year 2022 capital expenditures total between $85 million and $95 million. The company forecast fiscal second quarter 2022 net oil production to average 7,250 barrels to 7,500 barrels per day with total net equivalent production of 9.4,000 to 10,000 barrels of oil equivalent per day. The gas and NGL cells during February through April will be impacted from an expansion underway at our midstream partners facilities leading us to provide the wider range of guidance. Once complete, the plant can provide additional takeaway capacity to our operations, which will further reduce flaring of natural gas and expected to increase sales volumes. Though our production on equivalent basis appears to be flat quarter of quarter, we do see oil production continuing to grow. The company forecast second LOE cost of between $6.5 million to $8 million, which includes increases for inflationary cost increases we have realized to date. 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 and processing facility. We forecast cash G&A expenses of approximately $3.5 million to $4.5 million excluding share-based and unit-based compensation expense and after the effect of gross profit from contract services derived from management services agreements. We believe that this level of capital investment corresponds to full year growth of approximately 11% to 15% as compared to fiscal year 2021 production levels. Now I'll turn the call over to body for closing remarks.

Thank you, Kevin. In summary, the company delivered another solid quarter. We're excited about 2022 for a number of reasons. Oil sales dominate our business and the combination of forecasted production growth, stronger market prices and the roll off of some of our lower price hedges may lead to materially higher net effective revenues from oil sales. On the gas side, we have line of sight on growing processing plant capacity with our midstream partners, which then combined with stronger pricing and gas and NGL markets leads to these commodities, contributing more to our bottom line. As we discussed, we are excited about the next steps in our EOR project developments and the coming quarters and we look forward to sharing more progress in this area. Overall, our plans remain on track and poised for execution. Thank you again for your support and your time today. Operator you may now open it up for questioners.

Thank you. We'll take our first question from Neal Dingmann with Truist. Q - Neal Dingmann Good morning all. Thanks for the update. Bobby, my first question is on the traditional production and associated cash flow. Maybe for you or Kevin given the stellar balance sheet you'll have, and your ability that we've seen now over the last several quarters to quickly boost production win and if you choose, given that I would, that you obviously as Philip mentioned, the lower prices are up. Why not push production a little bit, maybe from the normal kind of 13 wells a year to take advantage of the current higher prices that are out there. If there's any thoughts about doing that.

Okay. Thanks. Thanks Neil. It's a great question. So I will tell you that we're evaluating what our options are here, the next couple quarters, having that in our pocket to accelerate our drilling program, if the material and the rig is available is something that we're seriously considering and we'll probably address in the upcoming timeframe pretty quick. So we will kind of want to stay disciplined to the point that we keep within our guidance, but obviously we're looking at these inflated prices and want to take opportunities. So I think you'll see that in our upcoming forecast. Q - Neal Dingmann No great, great to see and great to have the flexibility. And then my second question is really on the EOR and CCUS Bobby, you and Kevin briefly mentioned upcoming timetable around the EOR Associated CO2. So first, can you talk about maybe what would you all would need to see in night? I don't want to get too far ahead, but curious to know what y'all would need to see in this first EOR project to potentially move to a second? And then maybe if I could just tie another one and obviously given that CCUS projects are separate from this, is there any update on any potential upcoming CCUS project obviously as a side of outside of what you're doing on this first EOR?

Okay. Neil, I'll take the first part and then I'll let Philip kind of address the second part. Kind of, as we talk in the presentation, the infrastructure is now in place on the pilot project, which is basically one half of a 960 acre unit. We anticipate starting with water injection within the next couple of weeks and we'll expand that water injection over the next couple of months. Sometime in late June, we expect to start taking first delivery of CO2 from Kinder Morgan and then we'll be implementing what's known as a WAG process water alternative gas. We will monitor that for the first six to 12 months to look at what our injection profiles look like so that we can optimize what we want to be considered our sweep efficiencies. And then what we're seeing in production response so that we can start modeling what the cost profile would look like on expanding a project. That's going to take probably a few months say maybe up to six months before we actually start getting enough hard data to consider expanding the first EOR pilot. For the second question, I'll let Phillips respond to the CCUS.

Yeah, thanks Bobby. As Bobby noted in his intro, we're working with various groups navigating the various requirements that make up a good project. We're not at the point to announce something right now. I think the way I'd characterize it is that we're talking to different groups. We're trying to decide, where exactly in the value stream we want to participate. An example there is whether you want to own the carbon capture equipment and own the full A to Z to capture the value chain there. Or if rather, we're just going to do a part of it. And an example there is maybe more of a fee for service where somebody else potentially with a lower cost of capital and a bigger tax appetite could own the equipment whereas we can be a partner there for the carbon sequestration and permanent storage. At the same time, we're working to understand regulations and land examples include, plume modeling how much surface and mineral we want to scope out ensure that we have adequate room. The same time, the build back better plan that was heading one direction towards the very end of last year. That of course changed directions and we want to have something that's flexible that of course works and the current regime, but then has potential for upside should the code with 45-Q change to the better. Hope that answers your question for the time being. Q - Neal Dingmann No, no, it does Philip, I guess it's just a matter of, kind of what offers and sort of how the contracts shaped out. Sounds like you have a lot of opportunity, the CCUSs, it's just a matter of which people maybe present you with the best opportunity to go forward, is that fair?

Yeah. I think that's a good way to put it. And then at the same time, overlaying certain costs, what does it cost to bond these things? This is innate field. I'd encourage anybody who's reading headlines to really dig in on some of those and you may find that some of the headlines, there's less actually there for people that have gotten, say a truly underwritten insurance policy for some of the storage. So those are the types of things we're doing. Q - Neal Dingmann No, it's just, I love the optionality on both the CCUS side. All right, guys, keep up in good work

Next. We'll go to John White with ROTH Capital. Your line is open.

Hey really nice to see the improved results on natural gas and NGO pricing. A follow up on Neil's question on the EOR project and you laid out a precise timeline on water and CO2 injections, and I take it from the timeline you've laid out meaningful oil production from the EOR project. It's probably, would you say mid 2023?

I think that that's a year from now. We will have significant data to support whether we're where and how to expand the project. I expect we will start seeing some response prior to that. You don't want to push it to get response too fast because you want to try to design a very efficient sweep structure so that you're not bypassing. So this is not something that you want a cram in the hole for immediate results. It's going to take a little time, but I expect by mid '23, we should be on this initial -- on this initial pilot, we should be reaching kind of peak performance on what we initially what we were looking for.

I appreciate the detail as call cautionary remarks. Thanks a lot. I'll pass it on.

We'll next go to Noel Parks with Tuohy Brothers. Your line is open.

Just got a couple questions, just sort of re refresh me on where things stand with your process of the gas processing capacity expansion. And you mentioned there was a little bit of uncertainty ahead around just when the operator, I guess might have some downtime, if you could just expand on that a bit,

Kevin?

Yeah, so they have started the process to or well underway on the expansion project. We anticipate that at we'll seek curtailment through early to mid-April, at which point we will be able to start selling full stream of our Champions operating gas into the system.

Okay, great. And are there are there subsequent stages after that sort of mid-April capacity comes online or will that basically take you to where you need to be for near term?

It'll take us to where we need to be near term in the future, there may be need for additional expansion projects as the field continues to develop.

Great. And you talked a bit about keeping an eye on just what cost and rig availability looked like as you execute your plan for the year. Just was wondering on the side of the pace of completions, just kind of what you're planning. What advantage of course of as you have hedges roll off there's you have opportunity of course, for more upside if oil prices stays strong. So is that something you're also flexible around your completion pace through the year?

Well, we do anticipate currently completing all the wealth that we drill during this quarter or this year, especially being that most of our activity is heavily weighted to the first half of the year. All the wells that we currently have scheduled, we'll be producing during this fiscal year for some amount of time. But one of the things that we do consider if we are to add well in this fiscal year, what's the impact of that well, and the timing of bringing it online. So we would want to add something in the next six months versus waiting post.

Okay. Okay, great. That's all I have. Thanks.

There are no further questions at this time. I'll now turn the call back over to Bobby Riley for any additional or closing remarks.

Okay. Thank you. And thank you everybody for joining the call today. We look forward to talking to you in the next quarter. Thank you.

This concludes today's conference call. You may now disconnect.