National Fuel Gas Company

Ladies and gentlemen, thank you for standing by and welcome to the Q3 2020 National Fuel Gas Company earnings conference call. At this time, all participants 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 then 1 on your telephone keypad. Please advise that today's conference is being recorded. If you require further assistance, please press star 0. I would now like to hand the conference over to your speaker today. and Ken Webster, Director of Investor Relations. Please go ahead, sir.

Thank you, Ian, 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 John McGinnis, President of Seneca Resources. At the end of the prepared remarks, we will open the discussion to questions. The third quarter fiscal 2020 earnings release and August investor presentation have been posted on our investor relations website. We 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 only as of the date on which they are made and you may refer to last evening's certain specific risk factors. National Fuel will be participating in the Barclays Energy Conference in September. Please contact me or the conference planners to schedule a meeting with the management team. With that, I'll turn it over to Dave Bauer.

Thanks, Dan. Good morning, everyone. As with most oil and gas companies, Lower commodity prices weighed on the third quarter, gathering business. However, the remainder of the system had a very solid third quarter, with pipeline earnings up nearly 45% on the strength of supply corporations' recent rate settlement and stable utility earnings in spite of the COVID pandemic. All told, the quarter was another great example of the benefits of our integrated, diversified model, where the earnings and cash flows of our regulated businesses provided a strong measure of stability against the more variable earnings of our E&P business. Operationally, this was a really significant quarter for National Fuel, one in which we reached several important milestones that make us well positioned to deliver meaningful growth in the years to come. First and foremost, last week we closed on the acquisition of Shell's upstream and midstream properties in Appalachia. This is a terrific opportunity to check all the boxes we were looking for in an acquisition. From start to finish, it was the result of the exceptional work of dozens of employees across our upstream and midstream operations. Hats off to the team on a job well done. The acquisition meaningfully increases our presence in Appalachia. In fact, earlier this week, Seneca's gross natural gas production crossed the 1 BCF per day threshold. This is a great milestone. To put it in perspective, in fiscal 2018, our average daily production was only about half that. With the added scale, we expect to realize immediate cost synergies, and you can see that in our guidance on cash operating costs, which we expect will be down about $0.05 per MCFD in 21. The financing kudos to our finance team and the banks that supported them for getting the deals done in the face of a challenging backdrop in the capital markets. It's a challenge for us to finance the deal with roughly 50-50 debt and equity, and I'm happy to say that we achieved that objective. In May, we issued $500 million of bonds, the proceeds from which, and to term out our revolver. Under $175 million, it was done at a better price than we would have received under the equity backstop arrangement available to us under the shell purchase and sale agreement. And lastly, earlier this week, we signed an agreement to divest substantially all of our Appalachian timber properties for approximately $116 million, which will fund the remaining equity needed for the transaction. The timber properties are a non-core asset that we've held for some time. The earnings and cash flows associated with them are modest, in fact, pretty close to break even. Reinvesting the proceeds from the sale allows us to avoid issuing another roughly 2 million common shares at the midpoint of our fiscal 2021 guidance That saves approximately $0.08 per share of dilution. In addition, the timber properties have a very low tax basis. By selling them now, we're able to structure the timber sale and shell acquisition as a like-kind exchange, and by doing so, defer a large tax gain. The remainder of Seneca's operations continue to run smoothly, and John will have a full update later on the call. but I'd like to emphasize the improvement we expect in this business in fiscal 21. As you can see in last night's release, the midpoint of our production guidance is 320 BCFE, a 32% increase over our expected production for fiscal 2020. In addition, with the NIMAC strip in the 265 to 275 area, there's cause for optimism on natural gas prices and we've been aggressive with our hedging program. At this point, about two-thirds of our fiscal 21 gas production is hedged. Both of these factors should cause cash flow operations to grow meaningfully. On top of that, as a result of moving to a single-rig program, capital spending at Seneca and NFG Midstream is expected to decrease by $105 million, or about 25%. Assuming the current strip, next year we expect more than $150 million in free cash flow. from our E&P and gathering businesses. Pipeline and storage segment is also positioned to deliver meaningful growth in 2021 and beyond, and several noteworthy events occurred during the quarter to help make that a reality. On the expansion front, we placed a portion of our Empire North project into service ahead of schedule, which allows us to capture some modest short-term revenue opportunities this summer. Once it's fully in service, which we expect will occur by the end of September. This project will add $25 million in annual revenues. In July, we received our FERC certificate for the FM 100 project and Transco also received their FERC approval for the companion Lighty South project. Both projects are on track for a late calendar 2021 in-service date. And as a reminder, the expansion portion of this project is expected to add $35 million in annual revenue. Lastly, in early June, FERC approved the settlement of Supply Corporation's rate case. As I discussed on last quarter's call, new rates went into effect this past February and are expected to add $35 million in annual revenues. The settlement also addressed the rate-making treatment of the modernization component of the FM100 project. On the later of the in-service date of that project, or April 2022, a step-up in rates will go into effect, providing an incremental $15 million in annual revenues. In total, the expansion projects and rate case settlement are expected to provide in excess of $100 million of incremental annual revenues for our pipeline business by mid-2022. To put that in perspective, our fiscal 2019 pipeline revenues were $288 million. So we're looking at some really meaningful growth in the next two years. In addition to improving earnings and cash flows, the growth in our pipeline business will help us maintain relative balance between the regulated and non-regulated portions of our company. On the utility front, despite the pandemic, our operations and financial performance remain right in line with our expectations. With the reopening of most of the economies in our New York and Pennsylvania service territories, our capital program has returned to pre-pandemic levels. We continue to focus on modernization projects that enhance the safety and reliability of our system, while at the same time reducing emissions. In New York, our system modernization tracker allows us to do this in a manner that minimizes the regulatory lag to recover these large investments. Given that we can add rate base to this tracker through March of 2021, we expect to maintain consistent returns at our utility for at least the next few years. Lastly, a few words on the COVID-19 pandemic. Thankfully, infection rates have been relatively moderate in western New York and western Pennsylvania, where the vast majority of our employees and customers reside. Overall, the business continues to run smoothly across the system. Employees who can work from home are doing so, and those who cannot, mostly our field personnel, have been provided appropriate PPE and are practicing social distancing. It's been an incredible effort by our employee group to get us where we are today, and I'd like to thank all of them for their hard work and dedication. In closing, despite the backdrop of a pandemic, it's an exciting time for National Fuel. We just closed the most significant acquisition in the company's history, and next year we'll start construction on what will be our largest pipeline expansion project to date. Our balance sheet is strong and will likely get stronger as we generate free cash flow. And we've extended our impressive dividend track record, having increased it in June for the 50th consecutive year. All of this makes National Fuel well positioned to deliver significant value to our shareholders in the coming years. With that, I'll turn it over to John for an update on our upstream operations.

Thanks, Dave, and good morning, everyone. In echoing Dave's remarks, we are excited to move forward after successfully closing on the acquisition of Shell's Appalachian upstream and midstream assets last week. At the time of closing, these shallow declining properties were producing around 220 million cubic feet per day net. This additional scale is expected to be immediately accretive to Seneca's cost structure. And to put this into context, our G&A expense as a result of the shell acquisition is expected to increase less than 5% in fiscal 21, while our net production is expected to increase by over 30%. Although our purchase price for these assets describe no value for the reserves beyond proved producing, We are working towards maximizing the upside as we integrate these assets into our overall development plan. We have now added significant Utica and Marcellus inventory in Tioga County, contiguous to our existing operations. In area, we have been active for over a decade and we know very well. In addition, we've also acquired valuable low-cost pipeline capacity, including $200 million a day of firm transport on National Fuels Empire System and $100 million a day on Dominion. In fact, as a result of this dominion capacity, which provides access to Lighty Hub, Seneca is in the unique position of being able to flow production from each of its three major producing areas into its FM100 Lighty South capacity. Moving forward, we will work closely with our midstream group to determine how to best integrate our development and pipeline activity, then minimize capital deployment, drive operating efficiencies, and maximize the value of these assets. Returning to our third quarter, Seneca had strong operational results, producing 56 BCFE, an increase of around 2% compared to last year's third quarter, despite 7.3 BCF of price-related curtailments. In response to sustained low natural gas prices, we reduced our activity to a single rig in June and have since curtailed an additional 2 BCF of production in the month of July. We have now curtailed around 30 so far this year. Moving forward, we expect prices to remain low over the next couple of months forecasting to curtail our remaining spot volumes for the rest of this fiscal year. While pricing and related curtailment put a damper on Seneca's results for the quarter, operationally, we're very pleased with our business. We continue to drive down our well costs and have seen an 18 to 20 percent improvement this year compared to last. This cost reduction has been driven primarily through fewer drill days per well, improved efficiencies and lower service costs across the sectors. We will provide an updated well cost economics table in the investor deck next quarter. In California, we produce around 584,000 barrels. of oil during the third quarter, an increase of 2% over last year's third quarter. Fortunately, with approximately 80% of our oil at an average price of about $6 million, we're well positioned to weather the downturn in oil prices. Taking into account our price-related natural gas production curtailments, We are decreasing our fiscal 20 production guidance slightly to range between 240 to 245 BCFE. We are reiterating our CAPEX range of $375 to $395 million, around 20% lower than fiscal 19 at the midpoint. Moving to fiscal 21 guidance, we are currently planning to remain at a one-rig pace in Pennsylvania. Due to our lower activity level with only a single rig and completion crew operating in Pennsylvania, our $290 to $330 million range of capital expenditures for the year represents a 20% decrease at the midpoint of our fiscal 20 guidance and a 35% decrease from fiscal 19. Fiscal 21 net production is expected to be in the range of 305 to 335 BCFE. have all received a 32% increase versus fiscal 20. This increase is driven almost entirely by the production acquired from Shell. With only a single rig operating in Pennsylvania, we plan to bring to production 32 wells next year, 16 Marcellus and 16 Utica. As to production cadence, 27 of the 32 wells are to be brought online during the first seven months of our fiscal year. In California, we have deferred our development program until oil prices improve, and therefore we're only currently forecasting to spend around $10 million in CapEx next year. Unlike other oil-producing basins in the U.S., however, our California assets enjoy a low rate of decline. However, if prices improve, we will move to quickly return to our development program. and with approximately 49% of our oil production hedged in fiscal 21 at an average price of $58 per barrel, we will continue to generate free cash flow even at today's low prices. In fiscal 21, through physical firm sales contracts as well as our firm transport capacity, we have secured marketing outlets for around 91% of our expected Appalachian production and two-thirds protected with price certainty for the downside protection of $1.37. For sale into the spot market. But as always, when we see opportunities, we will layer in additional firm curtailments. And finally, we continue to be very pleased with how our Seneca team has conducted business through the impact of the pandemic. Our offices remain closed except for those who need access. and our operations team has done a great job continuing to operate successfully and safely in the field during this period. And with that, I'll turn it over to Karen.

Thank you, John, and good morning, everyone. Gap earnings per share were 47 cents for the third quarter. Adjusting for items impact and comparability, including the ceiling test impairment charge recorded in our E&P segment, adjusted operating results were 57 cents per share. a decrease of 14 cents from the prior year. Drone results from our pipeline and storage segment due to the impact of the supply rate case and lower operating expenses were more than offset by lower natural gas and oil price realizations. Last night's release explains the major earnings drivers, so I won't repeat them here. Instead, I'll discuss our expectations for the remainder of the fiscal year and our initial guidance for next year. As it relates to fiscal 20, Our updated earnings guidance is $2.75 to $2.85 per share, a decrease of 10 cents at the midpoint. This change is due to a few main drivers. As John mentioned, the largest decrease can be attributed to price-related curtailments during the third quarter and approximately six BCF of additional curtailments expected during the fourth quarter. These curtailments will have a corresponding reduction to throughput in the gathering segment. From a pricing perspective, we've revised our NYMEX gas and WTI oil assumptions, but given our strong hedge position, these changes generally offset each other from an earnings perspective. Additionally, we've reflected the execution of our permanent financing for the Shell acquisition. Given the market backdrop, we completed the necessary financing well ahead of closing and upsized our debt issuance to term out our revolver and enhanced liquidity in advance of our December 2021 maturity. As it relates to the rest of our assumptions, there was some movement of expenses between the third and fourth quarter in our regulated subsidiaries, but substantially all of our other guidance items for fiscal 20 remain intact. Looking forward to fiscal 21, we are expecting a material increase in earnings per share when compared to fiscal 20. We're initiating preliminary guidance in the range of $3.40 to $3.70 per share, an increase of nearly 27% at the midpoint. This range excludes the impact of any future ceiling test impairments, which we expect to incur in the fourth quarter of this fiscal year, as well as the first quarter of fiscal 21, based on the forward curve as of today. Our fiscal 21 pricing assumptions and hedge positions are outlined in last night's earnings release. So I won't repeat that information. As a reminder, even with the level of hedges we have, given our base of production, changes in pricing can impact earnings for the year. For reference, a $0.10 change in natural gas prices is expected to impact earnings by $0.11 per share, a $5 change in oil by $0.04 per share. The biggest driver of the year-over-year earnings increase relates to the impact of the Shell acquisition in both the E&P and gathering segments. Production is expected to be up nearly 80 BCFE at the midpoint, in excess of 30% from fiscal 20, the bulk of which comes from the acquired assets. All of this incremental production will flow through our gathering systems and is expected to lead to $185 to $200 million in revenue for our gathering segment. This is an increase of approximately $50 million from fiscal 20, or approximately 35% at the midpoint. A portion of this revenue growth will be offset with slightly higher expenses related to the acquisition, where we now expect O&M expense in the segment to be approximately 8 to 9 cents for MCFE of gross throughput. This is driven by higher compression lease expense. With respect to our legacy gathering facilities, we typically don't lease compression equipment. So therefore, this has the effect of a higher per unit O&M expense as we recognize the lease costs on the income statement. In addition, we are forecasting higher depreciation expense related to the allocation of the acquisition purchase price and the higher plant balances on existing operations due to capital spending during the course of fiscal 20. We generally assume a 25-year depreciable life on these assets which will drive an $8 to $9 million increase in depreciation in the gathering segment. In our regulated businesses and the utility business and a nice increase in the pipeline and storage segment due to the Empire North expansion project and the full year impact of the supply corporation rate case. Focusing first on the utility, there are three major moving pieces. First, we're forecasting a return to normal weather. For the first nine months of fiscal 20, weather was 8 to 11 percent warmer than normal across our service territory. This reduced margin by about $5 million, the majority of which was in our Pennsylvania service territory where we do not have a weather normalization clause. In addition to normal weather, we are forecasting a continued increase in margin related to our system modernization tracker in New York. which we expect will add approximately $3 million to margin in fiscal 21. Going in the other direction is a modest 1% to 2% increase in O&M expense in line with inflation. Touching briefly on the pipeline and storage segment, we expect revenues to increase approximately 10% driven by the full year impact of the supply rate case of which we only saw eight months of impact in fiscal 20 and the Empire North project, both of which Dave touched on earlier. Collectively, these items will add approximately $35 million in revenue next year. Partially offsetting these revenue additions is forecasted recontracting that happens in the normal course of business, as well as a reduction in short-term contracts, which we don't assume to recur. On the expense side, we expect O&M to increase by approximately 3-4%, partially driven by general inflationary assumptions and the remainder due to expenses from the operation of two new compressor stations associated with the Empire North expansion project. Additionally, we expect to see an increase in depreciation expense due to higher depreciation rates that were part of the Supply Corporation rate settlement, as well as normal increases due to higher plant balances and placing Empire North in service. Turning to our capital plans, as laid out in the earnings release, our consolidated fiscal 20 guidance remains unchanged and we expect capital spending to remain relatively flat into fiscal 21. Further details of our capital guidance are described in the earnings release. From a financing perspective, given our relatively flat capital spending forecast and 25% plus forecasted earnings growth, we anticipate generating in excess of $100 million in consolidated free cash flow in fiscal 21, exclusive of our dividend. Combining the end of the year resulting from the timber sale, we don't anticipate the need for incremental borrowing next year, even as we embark on one of the most capital-intensive pipeline projects in our history. Looking beyond fiscal 21, we expect our cash from operations to cover capital spending and our dividend, which will lead to the continued strengthening of our balance sheet. In summary, we're in a great spot financially. We've successfully financed the acquisition of Shell's Appalachian Assets, anticipate closing on the sale of our timber properties in the next few months, and capitalized on the opportunity to enhance our liquidity with an upsized debt issuance. We don't have a debt maturity until December of 2021, so we have a good amount of time to monitor the capital markets for the right opportunity to complete that refinancing. With that, I'll close and ask the operator to open the line for questions.

At this time, if you'd like to ask a question over the phone lines, please press star then one on your telephone keypad. We will pause for a moment to compile the Q&A roster. Your first question comes from the line of Holly Stewart of Scotiabank. Your line is open.

Good morning, gentlemen. Karen? Hi. Hi, Holly. Maybe first question for John. John, I know we've talked about this on past calls, but just as you think about the activity level, I know you've noted before that you wanted to see more than just You know, a rally in 2021. We're starting to see that based on, you know, where 21 and 22 strip is heading. So just, you know, kind of wanted to revisit that topic and see where we go from here in terms of potentially adding capital back to the business.

Yeah, thanks, Holly. Actually, you're exactly right. And to tell you the truth, we are approaching prices. That makes sense. But to tell you, once we get some visibility related to the on-light date of Lighty South, I think we would certainly consider adding back that second rig a few months prior. So we are already looking at that. Honestly though, right now it still doesn't make sense to add a rig just to produce into the spot market. It has to be tied to as we grow into these opportunities to get our gas into some premium markets. But we are, this is definitely something we're evaluating as we speak.

Okay, and as you think, a follow-up to that, I guess, as you think about that, would that rig go to work in the EDA?

It most likely would. We're thinking Tioga first and then moving where we need it. We would move the rig after that where we need it.

Okay, great. And then, you know, maybe just thinking about the overall FT capacity, you've got the new shell capacity that's come on. Your Existing Portfolio, and then the FM100 project. So I'm assuming your end market exposure shifts a bit and actually probably improves. So how should we think about those changes to end markets?

Yeah, actually it does improve. We're probably looking at a 10 to 15 cent per MCF improvement, bringing on the new shell assets. compared to our current or our previous. So we get a 10 to 15 cent improvement on that.

Okay. And then that's great. And then maybe just one more for me if I could. On the pipeline side, the FM100 project, what's next from the regulatory standpoint before you can begin construction?

Well, we have to wait to get some state permits that are still outstanding. We don't see any issues with them, but the various PA environmental agencies and the Army Corps have to work through that process, and we'd expect that in the calendar fourth quarter of this year. Then after that, we request a notice to proceed. which we would expect FERC to grant in short order and then we'd begin construction likely with tree clearing in late winter and then full-on construction next summer.

Got it. Thank you all.

Yep. So our next question comes from the line of Gordon Loy of Raymond James. Your line is open.

Good morning, Alan. Thanks for taking my questions. Morning. Just a couple questions for John. I'm looking at the call it $300 million in E&P capital for fiscal 2021 and then off of the 32 wells that you guys plan to bring online. Of those 32 wells, I guess what's the duck drawdown that's built into that?

Yeah, actually we're going to be drilling 23 wells total. and completing 40. So yeah, we'll be certainly completing more wells than we're drilling. We're bringing those 32 on and currently where the duct count, I think it's around 19 right now, 18 to 20. So we will certainly burn into that duct count over the next 12 months.

Got it. That makes sense. And then my follow-up is, I mean, back when you guys announced the shell acquisition, you guys had this slide that's talking about The base declines for Shell and Seneca were both in kind of the low 20% and then the expectation was that the Shell asset base decline would decline to sub 20% at closing. I guess I just wanted to see if I could get an update on kind of where those base declines are and kind of what kind of base decline is assumed for fiscal 2021 for the entire business.

Yeah, absolutely. Currently, the shell wells are on around a 20% decline, so pretty much in line with what we're thinking. And our Seneca add-on, so all in, including the Seneca assets, we're looking at maybe 20% to 22% base decline.

Got it. That's helpful. That's all I had. Thank you.

Again, if you'd like to ask a question over the phone lines, please press star then 1 on your telephone keypad. Your next question comes from Chris Signolfi of Jefferies. Your line is open.

Hey, everyone. This is Ryan on for Chris. First, John, I know you touched on this a bit in your prepared remarks, but I wanted to ask you about the CapEx guidance of $290 to $330 million. I believe on last quarter's call you gave a soft guide of $350 million, so I'm just wondering what's changed and if there's anything in a shell acquisition that would be driving capital efficiencies. And similarly, we noticed unit costs are expected to come down about 6% year over year. So anything you can offer on those two things would be great.

Okay, sure. Thank you. Yeah, our costs, our drill efficiencies have improved dramatically. We're drilling a lot of our Utica wells a lot quicker than we used to. We're seeing efficiencies actually across the entire board on our completion as well. So we've been able to drive down costs as a result of that. So that's one of the movers. Another reason for it is earlier this year we had drilled four Utica wells in 007 and had decided that we would defer completing those until sometime next year. But based on the pricing that we're seeing moving into this winter, we decided to accelerate that and we're currently completing those wells. And we should see those, I'm thinking that will come online late our first quarter of fiscal for some capital from fiscal 21 into fiscal 20. In terms of our per unit cost, really the big driver there is the GNA, as I stated, in earnings increase as a result of that. Like I said, we're increasing our GNA by 5% related to the shell acquisition, but our production is increasing by well over 30%. Okay, perfect.

Speaking with cost, we noticed a relatively large step up in O&M at the utility versus a pretty steep drop off at pipeline and storage business. So just curious sort of what was going on at the utility and if there was anything that would typically be capitalized but wasn't and was forced to be expensed due to work stoppages or anything like that?

Sure. At the What we're seeing is some elevated expense related to the pandemic, right? So it comes in a couple forms. One is higher PPE for the folks out in the field. on the one hand. And then in the second quarter, we had a dynamic where, and I suppose to an extent in the third quarter as well, where because a part of our workforce was idled, the cost of that labor was hitting O&M as opposed to being capitalized because that contingent would normally be working on capital projects. So that boosted O&M expense a bit. I think when you look at an overall trend, as Karen said in her remarks, it should be relatively stable, maybe in that low single-digit inflation area. It tends to be, except for the second quarter, it tends to be pretty stable. So the third quarter notional O&M rate is probably a good proxy for a run rate going forward. Again, the second quarter during the winter is usually quite a bit higher, you know, maybe 20 or 25% higher, but we wouldn't expect a big amount of cost increase from our current baseline. In fact, hopefully if the pandemic calms down, we'll see a moderation in expense. On the pipeline side, we're looking at some timing issues as to how expenses fall between quarters on the one hand, and then when you look at our compressor overhaul work, sometimes we're able to capitalize those costs if the jobs are really big, other times we have to expense it and we've got this dynamic where last year we had a lot of O&M compressor work and this year it happens to be more capital so you get that dynamic. I think when you You consider pipeline O&M looking at the last trailing 12 months is probably a good proxy for a baseline. But then add to that, I'd say somewhere in the maybe $2 to $3 million related to the growth that we've seen, particularly the Empire North project. And then as we begin to hire people to staff the compressor stations in the FM100 project. So that's a really long answer that I'm happy to be more specific on if I can.

No, that was great. Thank you for all that. And just one last one if I could. Karen, I know you mentioned that you didn't expect to need additional financing in fiscal 21, and that was one of my questions, but just an update on cash tax expectations next year. If you could.

Yeah. Yeah. So, yeah, we're not expecting to be in a cash taxpaying position next year. Next year. Nope.

Okay. Perfect. That's all for me.

There are no further questions over the phone lines at this time. I turn the call back over to Ken Webster for closing remarks.

Thank you, Ian. We'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, August the 14th. To access the replay online, 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 9086223. This concludes our conference call for today. Thank you and goodbye.