National Fuel Gas Company

Ladies and gentlemen, thank you for standing by and welcome to Q2 2022 National Fuel Gas Company Earnings Conference Call. At this time, all participants' lines are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star 1 on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star 0. I would now like to hand the conference over to your first speaker today, Brandon Haskett, Director of Investor Relations. Please go ahead.

Thank you, RJ, and good morning. We appreciate you joining us on today's conference call for a discussion of last evening's earnings release. With us on the call from National Fuel Gas Company are Dave Bauer, President and Chief Executive Officer, Karen Camiolo, Treasurer and Principal Financial Officer, and Justin Loweth, President of Seneca Resources and National Fuel Midstream. At the end of the prepared remarks, we'll open the discussion to questions. The second quarter fiscal 2022 earnings release and investor presentation have been posted on our investor relations website. You may refer to these materials during today's call. We would like to remind you that today's teleconference will contain forward-looking statements. While national fuels, expectations, beliefs, and projections are made in good faith, and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last year's earnings release for a listing of certain specific risk factors. With that, I'll turn it over to Dave Bauer.

Thanks, Brandon. Good morning, everyone. National field had a great second quarter. Adjusted operating results were $1.68 per share of 25% year-over-year, with each of our four major reporting segments contributing to the increase. Seneca had an outstanding quarter, both operationally and financially. Production for the quarter was up sequentially and relative to last year. That increase, combined with the ongoing rise in commodity prices, caused earnings to grow by 50% over last year. As we announced in last night's release, Seneca has entered into an agreement to sell our California operations to Sentinel Peak for $280 million in cash and $30 million in contingent consideration. Just as the spring of 2020 was a great time for us to acquire natural gas assets, we think the current oil price environment is the right time for us to sell our California properties. These have been great assets for us since 2010, generating over a billion dollars in cash flow that funded a good amount of our upstream and midstream growth in Appalachia. But the regulatory environment in California makes it difficult to grow those operations. Plus, as our Appalachian businesses have grown, our California assets were increasingly non-core. Sentinel Peak will be a great owner of these assets. They're an established operator in California with an excellent track record. Justin will have more details on the transaction, but before moving on, I want to personally thank the California team for their hard work and dedication to the company. We expect a June 30th closing date for the transaction. Net proceeds from the sale should be approximately $175 to $200 million after accounting for taxes, the April 1st effective date, and the unwinding of out-of-the-money hedges that will not be transferring to the new owner. Turning to Seneca's capital budget, we're revising capital spending guidance to a range of $475 to $550 million, an increase of $50 million at the midpoint. The majority of the increase is related to an acceleration of completions activity later in the fiscal year. This was an easy decision given the strength in commodity prices, particularly through this upcoming winter. It allows us to capture a better than $3 price differential between winter and summer pricing and pays out in under a year. The remainder of the increase in capital relates to ongoing cost inflation. Like most of our peers, we're seeing inflation across the board on materials and services. Justin will have more on this in a few minutes. Moving to our pipeline business, this was the first full quarter of operations on the FM 100 project, which was the principal driver of the 14% increase in revenues on our interstate pipeline system. Everything about the project is performing as expected. You may recall there are two revenue streams associated with the project, $35 million in incremental expansion revenues and a $15 million increase in supplies base rates to reflect the modernization component of the project. that $15 million base rate increase went into effect as planned this past April 1st. Not only does FM 100 provide a great tailwind for the FERC regulated businesses, but it also bolsters Seneca's firm transportation portfolio, facilitating access to new markets to further diversify its future sales. The utility had another good winter heating season, providing the safe and reliable service that our customers expect. Importantly, despite the weather being consistent with last year, and despite the reduction in our PA rates due to the OPEB change that we discussed in the earnings release, the utility experienced growth in customer margin thanks to our system modernization tracker in New York. Further, we continue to see modest growth in customer counts, which also added to margins. Because the weather improves, our summer construction program kicks into high gear. We have lined up all the contractor crews and sourced the necessary materials for the projects we have planned. No surprise, we are seeing cost inflation, but nothing that's overly concerning, at least at this point. And aggregate costs are roughly 10% higher than last year. We have another year left on our New York system modernization tracker, and it's been 15 years since we've last filed a rate case in Pennsylvania. And we're starting to look at the timing of a rate case there in Pennsylvania. So with that in mind, we're doing our best to accelerate our pipeline replacement program at the utility. And as such, now expect capital spending for the year will be in the range of $100 to $110 million. As you know, last December, the New York Climate Action Council published its draft scoping plan, which describes how the state plans to achieve its emission reductions goals. Recently, in-person hearings on the scoping plan were held across the state, including in our service territory. What was evident to me from those meetings is that while most everyone in the community, including us, is in favor of reducing carbon emissions in New York, there's a little consensus on how and at what pace we ought to do so. People are concerned with costs, and they're right to be. The scoping plan estimates that it'll cost, on average, $20,000 to electrify a home in New York State. But that cost could double in the Buffalo area, where houses are older and winters are more severe than in the downstate region. Further, it's estimated that electrifying the heating load in western New York would require a quadrupling of the energy grid, which would almost certainly add significant ongoing costs to customer bills. Energy reliability is also on people's minds. The scoping plan relies almost entirely on wind and solar, and everyone knows it's not sunny and windy all the time. We continue to advocate on behalf of our customers for a more reasonable approach to the energy transition, one that pursues aggressive energy efficiency measures and hybrid heating solutions, while continuing to leverage existing infrastructure to deliver low and no carbon fuels. Such a plan can meet or exceed the state's emission reduction goals, all while saving consumers money and without sacrificing energy reliability. Looking at the rest of the year on a consolidated basis, we now expect free cash flow from operations will be approximately $290 million, assuming the midpoint of our updated guidance ranges. Adding in the expected net proceeds from the California sale and total excess cash should be in the $475 million area. Looking out beyond this year with higher realized natural gas prices, along with mid to high single-digit production growth at Seneca, I expect free cash flow from operations will continue to increase. This outlook provides us with great flexibility. As I stated on last quarter's call, our first priority is to reduce leverage on the balance sheet with the hope of gaining an upgrade from the rating agencies. While our credit metrics will likely improve with the recent rise in pricing, we need to be able to sustain those metrics through the cycles, and to do so will require a reduction in our absolute debt levels. Lowering our absolute debt also improves our equity to capitalization ratio, which is helpful as we head into rate cases across the system. We also plan to invest in the continued modernization of our utility and interstate pipeline businesses. Doing so is a big win for everyone. System reliability improves, carbon emissions decline, and rate base grows. And I think there'll be further opportunities to expand our pipeline business. While projects of the size of FM 100 aren't likely in the immediate future, I do see continued demand for more modestly sized projects. But that isn't to say there isn't a need for significant new pipeline infrastructure in Appalachia. The United States is blessed with an abundance of low-cost natural gas in the Marcellus and Utica shales, and the demand for that resource is high, both domestically and abroad, particularly given the situation in Europe. But the pipeline infrastructure in the region is nearly full, and with the continuing backdrop of unfriendly state and regulatory policy, development of large-scale pipeline infrastructure has largely stalled. Without new pipelines, producers, including our own Seneca Resources, cannot continue to grow production in any meaningful way. As a result, we get the worst of all worlds, high prices and reduced energy security. And despite policymakers' best intentions, I think there's a good chance that carbon emissions will actually increase in the near term. As an example, this past winter, there were several periods of time when more than 20% of New England's electricity was generated using fuel oil, in spite of the fact that the Marcellus Shale is only a few hundred miles away. Undoubtedly, the industry is ready and willing to do its part to help fix the situation. There's more than enough natural gas reserves in the country to both temper domestic prices and help wean Europe from its dependence on Russia. All we need is more infrastructure. National fuel, with our unique suite of integrated assets in the core of the Marcellus and Unica shales, is well positioned to play a long-term role in the development of both the natural gas resource and building the infrastructure needed to get it to market. In closing, National Fuel had a great quarter. Our integrated model continues to deliver considerable benefits that are evident in our financial and operating results. Looking forward, we're entering a period of substantial free cash flow, which will give us significant financial flexibility. And our focus on ongoing emissions reductions will improve the sustainability of our operations and position us well for the future. With that, I'll turn the call over to Justin.

Thanks, Dave, and good morning, everyone. Before I get into the details of the quarter and future outlook, I want to touch briefly on the sale of our California properties. First and foremost, I want to add my sincere gratitude to the Seneca West Division team. The employees in our West Division, many of whom have been with Seneca for multiple decades, have been tremendous stewards of these assets and are managing the transition to a new owner with the utmost professionalism. This is no surprise and is what we've come to know from such a hardworking, dedicated group of employees. To the team, I just want to say thank you for all that you've given to Seneca over the years, and I wish you all the best in the future. They've already hit on the high points of the transaction, so I'll touch briefly on a few of the details. We've agreed to sell the properties to Sentinel Peak Resources for total potential consideration of $310 million, with an expected closing date of June 30. This consists of $280 million in cash at closing, subject to purchase price adjustments, and contingent payments with potential value of $30 million. The contingent payments are up to $10 million per calendar year from 2023 to 2025 and are based upon the average Brent price for each year. For each $1 per barrel that Brent averages over 95, Sentinel Peak will pay Seneca $1 million, with the contingent payment capped at an average Brent price of $105 per barrel. For those who are not familiar with Sentinel Peak, they acquired Freeport-McMoran's onshore California assets in 2017 and operate approximately 25,000 BOE per day. We believe they have both the scale and financial strength to be long-term, sound stewards of these assets. We have also had the privilege of being neighbors to Sentinel Peak and know the team and leadership well. We think their history of safely operating assets and ongoing commitment to environmental stewardship, combined with their financial wherewithal, make Sentinel Peak the ideal counterparty to prudently operate these assets well into the future. Switching back to Seneca's results, we had an excellent quarter with record production of 87.1 BCFE, an increase of 2% sequentially. We also brought online two Tioga County pads on the acreage acquired from Shell in 2020. Production from these two pads has been outstanding, further validating the prolific nature of the acquired acreage. The first pad was a five-well Utica pad in northwest Tioga County, and the second was a six-well Marcellus pad in the southeast portion of the county. Combined, these two pads are flowing at a choke-restricted rate of about 150 million cubic feet per day, and we have well over a decade of development inventory across this prolific acreage position. In addition, we secured a large key lease in Lycoming County, which adds about 10 highly economic Marcellus drilling locations that, once developed, will flow through our trout-run gathering system. Overall, during the quarter, we turned in line three pads, totaling 18 wells, and have now brought online 42 wells for the year, split 50-50 between the WDA and the EDA. As I've talked about for a number of quarters, we expected our turn-in-line activity to be front-loaded in order to fill our Lighty South capacity as quickly as possible. We fully executed on that plan, and for the remainder of the fiscal year, we were only expecting to bring online one new pad, seven Utica wells in the WDA, which should occur in the fourth quarter. As a result, Appalachian net production is expected to increase to about $950 million per day in the third quarter and then remain around that level until the end of the fiscal year, when we accelerate till activity headed into the winter. On that theme, looking out over the remainder of the fiscal year and into fiscal 2023, we see opportunities in our upstream and gathering businesses to accelerate production during an extremely attractive gas price environment. We are pursuing opportunities to both bring production forward through increased completion activity and to increase existing PDP through compression optimization. At NFG Midstream, we're utilizing existing compression to lower suction pressures and boost production levels in the near term. We are also looking at select opportunities to install new compression units ahead of prior schedules to enhance production over the next 12 to 18 months. At Seneca, we are achieving our aggressive drilling efficiency targets which in turn allows us to accelerate completions on a couple key pads earlier than expected. And our completions and procurement teams have successfully secured a spot frat crew that will commence work this summer and be able to complete more stages in fiscal 22 than previously envisioned. This will accelerate some of our planned fiscal 2023 activity into fiscal 2022, increasing our capital over the balance of the year. However, Ford gas prices are roughly $3 higher this winter versus next summer, so the returns are excellent, and we will generate significant additional free cash flow over the winter months as a result of these schedule changes. I also want to reaffirm that our long-term plans remain unchanged, with our two-rig program capable of delivering mid- to high-single-digit production growth over the next several years. Our increased capital guidance also accounts for continuing inflationary pressures. both those we are experiencing today and that we expect to emerge over the remainder of the year. We are indisputably in an inflationary environment. As I've talked about in the past, oilfield goods and services, such as tubulars, completion crews, diesel fuel, and frax hand, continue to experience inflationary headwinds, leading to higher costs for everyone in the industry. We've come out of a period where oilfield service costs were as low as they have ever been, and pricing needed to come up for those companies to retain talent and invest in new equipment. The good news is that we continue to realize operational efficiencies and commodity prices have substantially increased, allowing us to generate significant incremental free cash flow in spite of these higher drill and complete costs. Between our accelerated activity, which accounts for the majority of our increased capital spending and cost inflation, we are revising our capital forecast to a range of $475 to $550 million. Lastly, we continue to progress on our environmental stewardship efforts. To that end, we recently announced the successful completion of a 121-well pilot program under Project Canary's Trustwell responsibly sourced gas standard, representing approximately $300 million a day of our Appalachian production. This was the conclusion of a multi-month assessment process that evaluated many operational facets of our program, including methane emissions, water management, and well integrity. We received platinum and gold ratings for all the wells in this pilot, and when combined with our previous responsibly sourced gas designation under the EPPO Origin Program, we continued to differentiate our natural gas production, providing the opportunity to participate in the rapidly evolving RSG marketplace. In conclusion, Seneca is executing well on our plan. Our portfolio of valuable firm transportation capacity provides access to premium markets outside of the constrained Appalachian Basin. allowing us to grow production and generate increasing amounts of free cash flow. I think we are very well positioned for long-term success. With that, I'll turn the call over to Karen.

Thanks, Justin, and good morning, everyone. National fields gap earnings were $1.82 per share, while adjusted operating results for the quarter were $1.68, an increase of 25% from the prior year. The primary difference between our gap earnings and operating results was the impact of a one-time non-cash benefit of $0.16 per share. This was related to an approved tariff filing in our Utilities Pennsylvania jurisdiction we've previously discussed that permitted us to stop collecting post-employment benefit costs due to the overfunded nature of these plans. The order approved several items, including the unwinding of a previously recorded regulatory liability leading to the one-time non-cash $18.5 million dollar benefit recorded this quarter. On an ongoing basis, we also expect a reduction to margin of approximately $10 million annually and a corresponding decrease to EBITDA. This drop is fully offset by the elimination of the associated OPEB expense, most of which is non-service costs sitting below operating income. As a result, we expect no direct earnings impact in our Pennsylvania jurisdiction. We also agreed to refund a portion of the remaining regulatory liability through one-time and ongoing bill credits starting last October and extending over a period of five years. These credits will be funded by money previously set aside in a trust for the sole benefit of rate payers, resulting in no impact to operating cash flows. Switching back to our ongoing operations, I'll focus mostly on the outlook for the coming quarters, since results for the quarter were relatively straightforward. Starting with earnings guidance, we've revised our range, which is now expected to be $5.70 to $6 per share. This reflects several changes to our assumptions. First, we've increased our natural gas price forecast to average $7.25 per MMBTU for the remainder of the year, with basis differentials averaging $1. This reflects the average strip price over the past week or so. Given the volatility, it's worth noting that a 25 cent change in natural gas prices impacts earnings per share for the remainder of the year by roughly 4 cents per share. Our updated guidance also reflects the impact of divesting our California properties, assuming an expected June 30th closing date. This impacts two items. First, we've revised our production guidance to a range of 340 to 360 BCFE for the whole year. This reflects approximately 4 BCFE related to the sale of California and a modest production increase in Appalachia related to the accelerated activity that Dave and Justin discussed. Second, our unit cost assumptions have been revised lower to reflect the elimination of our higher cost California operations starting July 1. As we look forward, we expect Seneca's unit cost should decrease by at least 15 cents per MCFE on an annualized basis. As it relates to California, we are expecting to incur a tax gain on the net sale proceeds. Combining this with the increase in taxable income related to our improved results, we expect to be a modest federal cash taxpayer this year. We have an NOL carry forward of approximately $140 million and federal tax credits totaling approximately $40 million. We expect to utilize all of these federal tax attributes this year. When combined with expected state taxes, we should have a cash tax outlay of $25 to $30 million, or approximately 4% of pretax income. Looking forward, as bonus depreciation phases out over the next few years, we expect consolidated cash taxes to increase from the mid-teens next year to the 20% area in a few years. Turning to capital, we've increased our guidance range $60 million at the midpoint and now are projecting a range of $725 to $870 million. As Dave mentioned, combining this with our revised cash flow forecast and net proceeds from the sale of California, we anticipate roughly $475 million of available cash before any impacts of working capital. This will be more than sufficient to fully fund our dividend and positions us well to reduce our absolute leverage level. We ended the second quarter with approximately $220 million in short-term borrowings, half of which was related to hedging collateral on deposit with our counterparties. As we move through the year, we expect to pay down the short-term debt with our available cash flows as well as through the return of our collateral deposits as those contracts settle. The volatility in commodity prices makes it challenging to forecast working capital requirements, but as we move through the remainder of the year, the timing of cash flows related to Seneca's natural gas sales, the costs for the utility to inject gas into storage this summer, and any potential collateral requirements on our hedge portfolio will drive changes in short-term liquidity relative to our internal projections. To that point, we have ample access to short-term liquidity. In February, we executed an agreement with our banks for a new billion-dollar five-year unsecured revolving credit facility that was strongly supported by our bank group. Looking forward, we have $549 million of long-term debt set to mature in March of 2023. When you take the expected proceeds from the California sale, our outlook for significant free cash flow generation and the recent five-year extension of our revolver, we are in a great position to work towards our goal of reducing absolute long-term debt. We will continue to watch long-term interest rates, but unless there's an opportunity to lock in a favorable coupon, I would expect us to manage this liability through the use of cash on hand and short-term liquidity. On the credit rating side of things, our metrics continue to improve with debt to EBITDA expected to trend toward the two and a quarter times area by the end of the year and FFO to debt approaching 40%. Combining this with our goal to reduce absolute leverage levels, we believe we are positioned well to improve our credit rating to the mid triple B level. We think this is the optimal credit rating for us, providing continued access to a lower cost of capital and balance sheet flexibility while offering sufficient cushion to weather broader macroeconomic challenges that we may face in the future. From an overall financial perspective, national fuel is in a great spot. With the completion of the FM100 project, we've hit an inflection point where we expect to generate meaningful and sustainable free cash flow. This offers us the ability to focus on multiple fronts, including near-term deleveraging while retaining the flexibility to maximize value for our shareholders through the prudent deployment of capital in the future. With that, I'll ask the operator to open the line for questions.

Thank you. As a reminder, to ask a question, please press star followed by the number one on your telephone keypad. Again, that is star, then the number one. To withdraw your question, please press the pound or hash key. Please stand by while we compile the Q&A roster. Your first question comes from the line of Neil Mehta with Goldman Sachs. Your line is open.

Good morning, team, and thanks for all the perspective here, and congrats on the recent sale. The first question I have is just talking through your hedging strategy. You gave some good sensitivities around your natural gas sensitivity for 2022, but talk about your hedge position in 2023. and how sensitive you are to movements in Henry Hub.

Good morning, and thanks for the question. We'll guide out our exact production or expect to guide out our production for fiscal 23 likely at our next call. But within our disclosures, you can see that generally speaking, we have A number of hedges that kind of roll off. So our relative percent covered will be lower and therefore the exposure to upward prices will be quite a bit higher. And then, you know, I guess overall, I would I would tell you that the, you know, the strategy we have remains intact. And we've got a lot of flexibility within our policy, but we've also moved more recently towards collared approaches to try to retain a lot of upside and, frankly, take advantage of the positive skew in the market.

For more clarity there. And then talk about what can drive longer-term earnings growth. Any debottlenecking opportunities in Appalachia or incremental growth projects that will drive the vector of earnings growth higher.

Yeah, I think this is Dave. I think we've got a great opportunity to continue growing the company. On the upstream side, through firm sales, we're able to grow our production kind of in that mid to high single digits area for at least the next few years, which for us is a decent percentage, but relative to the total market isn't a huge amount of volumes that'll be coming to the market. So I don't see us really moving prices. And then on the regulated side, you know, we've got really two things. One is, is the continued modernization of our, uh, our systems. You know, so if you look at our, our past history, we've been spending, you know, in the hundred to $110 million range on the utility. Most of that's modernization that has a, you know, nice, nice upward trend on, uh, on rate-based growth. Uh, similarly on the pipeline side, uh, we spend in call it the 50 to $70 million area on, on modernization that, uh, you know, also helps with rate-based growth. On top of that, I do think we can continue to do expansions on our pipeline system. We just recently did an open season on our line end and are sorting through the service requests that we got there. You know, we're optimistic that we can have a project that, you know, rough order of magnitude could be in the, you know, the 100 to 200 million per day type size. And then Empire North, we expanded last year, and I think we've got the ability to add a third compressor to that project, and we're chasing that. So is it going to be double-digit growth? No. But will it be modest, call it mid-single-digits growth? Yes.

Great call. Thanks, guys.

Yep.

Your next question comes from the line of Holly Stewart with Scotiabank. Your line is open.

Good morning, Joe and Karen.

Good morning, Allie.

Dave, Karen, I'm not sure which one of you want to take this one, but Karen, I know you talked a lot about accelerating the debt reduction program and sort of what you're targeting, but maybe from a capital allocation standpoint, is You know, maybe the first question would be, is there a targeted absolute debt level or maybe even a normalized leverage target, you know, assuming kind of a longer-term commodity deck maybe that we should be thinking about? And then, you know, I guess the bolt onto that would be, you know, kind of after, you know, you get to these targets, is bumping the dividend more than you historically have or maybe even a special dividend something that you would consider?

Yeah, from an overall target, you know, I think we'd like our, call it our equity to cap ratio to be in the, you know, call it low mid-50s area, you know, which is helpful in rate case proceedings. In terms of capital allocation, once we get beyond that, you know, certainly I'd I'd like to continue growing the company. You know, so our first priority is going to be to try to to do that. But beyond if there's the opportunities just aren't there, you know, a return of capital is certainly something that we would consider, whether it's a dividend or a buyback. You know, we'll we'll determine when when we get there.

Okay, Dave, and then maybe a follow-on to that would be, you know, obviously with gas prices doing what they're doing, you know, you're skewing to the non-regulated side of things in terms of kind of your balance. Is there, you know, is there a thought process of keeping that more level? Like, how do you think of those growth opportunities, whether they're, you know, internal or external? Yeah.

Yeah, I just, in the previous question, went through kind of the internal opportunities that we see. I'd like to continue to grow the regulated side of the business. You know, we've been active in looking at some of the assets that have been on the market, and I think given the environment, there's a good chance that additional regulated properties will be on the market, and we'll be looking at those as well.

Okay, that's great. And then maybe, Justin, just one for you on, you know, you've kind of kept the two-rig program in place, accelerating those completions in order to take advantage of the higher commodity price environment. I guess maybe how are you thinking about the 23 program, any, you know, kind of new factors that you're thinking through or weighing into that activity set, whether that's, you know, outlining 23 or even 24 at this point?

Yeah, so I'd say the team's just executing very well. So we're getting our wells drilled right in line with what I felt were pretty aggressive assumptions. And so that's kind of set us up for this opportunity where we can get after some completions a little bit earlier than maybe we previously had thought. And then even in spite of this tight service environment that everyone is in, we've been successful at getting – a crew to do a pretty significant amount of work for us starting at some point this summer. So that really, a lot of this activity is a combination of a little bit of bump to what previously we thought our production could be in fiscal 23, but it's also about shaping. And so when I talk about that, what I'm really referring to is trying to move production that we might have seen next summer and get as much of that into the winter as possible. You know, I didn't, The strip keeps moving so much these days, so it's hard to keep up. But generally, it's 3 to 350 higher to sell gas in, say, January versus April. And so to the extent we can do some things and overall maybe increase our volumes a little bit, but even almost as importantly, bring some of that activity in the winter, it's meaningfully accretive to us to do so. So that's the driver. And long term, You know, absolutely what we've been stating is very much our focus here. We've got, you know, mid to high single-digit production growth. Of course, that'll drive growth through the midstream business as well. And, you know, our program with two rigs and using a top-hole rig is really designed to achieve that, and we're protecting that future production through executing firm sales in excess of our firm transportation portfolio. So again, aligning to what we've always said, which is not growing just to grow, but growing into markets that we can get great prices in. So that's, I think it's just kind of a continuation of things we've been talking about with a little bit of modulation and the focus to 23 to really take advantage of the strong winter pricing.

Yep. Okay. That's great. Thank you guys.

You bet. Your next question comes from the line of John Abbott with Bank of America. Your line is open.

Good morning and thank you for taking our questions. Karen, I think this question is going to be for you. It's going to be on rate cases with utility business and growth in the utility business. So I listened to your opening remarks. It didn't sound like there was any change in the growth outlook for the utility business. but guidance for the utility business was sort of slightly reduced, even though you had a beat, it looks like, based on colder weather. So trying to understand it, because, you know, my initial impression, that might have been driven by the reduction, in the slight reduction in the rate case in PA, but what's driving that difference in growth for the utility business?

No, yeah, I don't think that we're anticipating much change to our growth in the utility business. I mean, we've always kind of talked that low single-digit growth where we've got some small addition of customers. We've got the system modernization tracker in New York that continues to allow us to grow rate-based there. Yeah, I guess I'm not seeing that we're expecting a change in what we have projected.

All right. Yeah, I thought the high end of the growth range previously was 4%. It just looked like it dropped down a little bit to 3%. So I was just trying to understand that.

Yeah, that's pretty much it. Yeah, go on. Sorry, John.

And then the other, and I guess, and so, again, this is actually a continuation of the first question. I've got a second question on the pipeline. So I guess it's probably least standard procedure, but just given inflation, I mean, the PA moved to reduce the rate case here because of, You don't need to recover for the retirement benefit. I mean, does that give you any sort of concern going into a rate case? Because you are experiencing inflation, so why do the lowering now?

Well, I think part of that was just kind of in response to the pandemic. The commissions had been asking utilities to find ways to reduce the impact of rates on customers, and this was something that we had developed over the years, this this overfunded OPEB liability, and it really just gave us the opportunity to pass those back to the customers. We're also able to lower our rates there, so then when we go in for a rate case, it's going to, you know, we'll be more likely to be able to, you know, get good response from the Commission to increase our rates for things like inflation.

And, John, one thing to keep in mind on the OPEB reduction, those dollars and expense were fully tracked and reconciled to rate recovery, right? So we could only use those OPEB dollars for OPEB expense, right? So we couldn't use it to offset inflation, for example. Does that make sense? So the dollars just sat in trust and we're now giving them back.

That helps out quite a bit there. And then the other question, again, this could be on the pipeline and storage segment, is that there was an increase in percentage for OEM. It looks like you're expected to be up 8% year-over-year versus 5% prior. You described that as pipeline integrity and fuel costs. I mean, what's the risk that actually goes even higher sort of looking at the 2023? How do we sort of think about that?

Yeah, we're not expecting there to be a huge impact from inflation there at this point.

All right. Very much appreciated. Thank you for taking our questions.

You bet.

Thanks. As a reminder, ladies and gentlemen, if you would like to ask a question, please press star followed by the number one on your telephone keypad. Again, that is star, then the number one. Your next question comes from the line of Trafford Lamar with Raymond James. Your line is open.

Thank you. Guys, thanks for taking my question. You know, my first question you already answered, it was about 23 production growth. A follow-up, it revolves around RSG. You know, you all achieved, you all have already achieved 100% certification under EO, 30% certified under Project Canary, I guess with regards to kind of the premium markets, what are you all seeing currently and kind of what are your thoughts on premium markets similar to net zero oil over the near and midterm?

Sure. So, you know, what I would share with you is that, you know, we actually have been successful at selling responsibly sourced gas, certified gas at a premium. The market is going to evolve in our assessment. I mean, the market's going to evolve a lot over the balance of this year and into the future. The premiums that you can achieve today, and I think I've mentioned this maybe in the past, but it's pennies. It's not nickels and dimes and quarters for that matter. It's pennies. But I think there's a lot of opportunity as it develops to see that improve. It somewhat depends on on what happens at utility commissions among various states, and if they want to embrace that part of decarbonizing and reducing overall emissions means differentiating natural gas and paying a premium specifically to natural gas that has a very low methane intensity associated with it, we could see that premium expand. I think there's also an opportunity, as you think about carbon credits and so forth, that You know, Appalachian natural gas is really the lowest methane intensity out there. It's way better than everything else. And so to the extent there's a way to kind of capture that more and define it and certify it better, I think there's an opportunity that can develop around that. We're still in very early innings. And we've been, as I mentioned, successful to date at selling some responsibly sourced gas. But I think we're early and it'll keep evolving. Perfect.

I appreciate that, Kelly.

Your next question comes from the line of Zach Parham with JP Morgan. Your line is open.

Hey, thanks for taking my question. I guess first one for Justin, can you talk a little bit more about what you're seeing on cost inflation, specifically what services where you're seeing the most inflation and And maybe give us a little color on how contracted you are on your rigs and other services that you're using going forward.

Sure. So I'll start with how contracted we are. So we have contracts that extend out through this year even into next year for both of our big rigs, which are high-spec rigs. So there's not a whole lot of near-term change in any of that. Similarly, we have a long-term contract for our main frat crew that extends out through the end of the year. And we continue to have discussions with them about, you know, extending that. So if you think of the real big line items, I mean, those are two of them. The places where, you know, the other services, not so much. I mean, very in contract terms. The price inflation, I mean, the biggest probably single item that absolutely everyone is looking at relates to steel costs. And so tubulars have gone up massively. And perhaps someone bought enough inventory to get through a certain period of time, a number of months. But the reality is every single person in our industry is facing increased steel costs. And they're massively increased. Fortunately, in Appalachia, our overall steel costs are a little bit less. than other plays. But nonetheless, that's a big one. You know, frack sand is tightened up very much. The spot crew market on frack spreads has gone up significantly from the prices that we saw last year. And it goes without saying to anyone in any business that things like diesel fuel and labor have gone up as well. So I think generally speaking, this is across the board. And we're just trying to be very transparent about exactly what we're seeing and get out ahead of it and make sure that, you know, as we've always done, we try to be transparent with our guidance and with our commentary on all of this. And this is what we're just calling it as we see it. And so that's what's ahead of us. We've also baked in definitely what we've experienced of late and see in existing contracts as well as trying to think about where we see the market going. so that we capture it more holistically. So, I mean, that's really the punchline on inflation. Hopefully that helps.

That's helpful, Culler. I guess maybe just following up on that, on a cost per foot basis, where are your costs running now on the wells that you're drilling?

Yeah, so I'm happy to follow up with some more detail on that, but what I will tell you is that we're actually below, on a dollar per foot, we're below our costs of 2021. But that's largely because we've been able to move to areas where we are drilling longer laterals. And so the velocity and the overall spend is higher, but through our operational efficiencies, through the flexibility we have, through our highly contiguous large WGA acreage, and our meaningfully expanded position in Tioga, where we can drill much longer laterals than perhaps we could before, On a dollar per foot basis, we're actually kind of neutral to down from last year, but we're just getting more TLL.

Got it. That makes sense. That's all for me. Thanks.

And there are no further questions over the phone line at this time. I would now like to turn the call back to Brandon for any additional and closing remarks.

Thank you. Thank you, RJ. I'd like to thank everyone for taking the time to be with us today. A replay of this call will be available this afternoon on both our website and by telephone and will run through the close of business on Friday, May 13th. To access the replay line, please visit our investor relations website at investor.nationalfuelgas.com and to access by telephone, call 1-800-585-8367 and enter conference ID number 456-4187. This concludes our conference call for today. Thank you and goodbye.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.