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National Fuel Gas Co (NFG) Q3 2020 Earnings Call Transcript

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NFG earnings call for the period ending June 30, 2020.

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National Fuel Gas Co (NFG 0.07%)
Q3 2020 Earnings Call
Aug 7, 2020, 11:00 a.m. ET


  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Ladies and gentlemen, thank you for standing by and welcome to the Q3 2020 National Fuel Gas Company Earnings Conference Call [Operator Instructions]

I would now like to hand the conference over to your speaker today, Ken Webster, Director of Investor Relations. Please go ahead, sir.

Kenneth E. Webster -- Director of Investor Relations

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 vmay 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 Fuel's 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 evening's earnings release for a listing of 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.

David P. Bauer -- President and Chief Executive Officer

Thanks Ken. Good morning, everyone. As with most oil and gas companies, lower commodity prices weighed on the third [Technical Issues] 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 Corporation's recent rate settlement and stable utility earnings, in spite of the COVID pandemic. Also 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 are looking for in an acquisition. From start to finish, it was the results 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. And to put in perspective, in fiscal 2018, our average daily production was only about half of 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 Mcfe in '21. The financing for the transaction is complete. Kudos to our finance team and the banks that supported them. We're getting the deals done in the face of a challenging backdrop in the capital markets. As I described a few months ago, the plan was 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 were used to fund the debt component of the acquisition and to term out our revolver. We also raised just under $175 million through a common equity offering that 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 our 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, is a like kind of 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 NYMEX strip in the $2.65 to $2.75 area, there is 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 from 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%. So, putting it all together, assuming the current strip, next year we expect more than $150 million in free cash flow from our E&P and gathering businesses.

The 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 growth -- 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 FM100 project and Transco also received their FERC approval for the companion Leidy 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. 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. And 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 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 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.

John R. Pustulka -- Chief Operating Officer

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 ascribe 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, an 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 Fuel's Empire system and 100 million a day on Dominion. In fact, as a result of this Dominion capacity, which provides access to Leidy Hub, Seneca is in the unique position of being able to flow production from each of its three major producing areas into its FM100 Leidy South capacity. Moving forward, we'll work closely with our midstream group to determine how to best integrate our development and pipeline activity, minimize capital deployment, drive operating efficiencies and maximize the value of these assets.

Turning 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 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 13 Bcf of our gas production so far this year.

Moving forward, we expect prices to remain low over the next couple of months and therefore we are now forecasting to curtail our remaining spot volumes for the rest of this fiscal year. While pricing and related curtailments put a damp around 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% 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 produced 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 production hedged for remainder of the year at an average price of about $60 per barrel. We are 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 million 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 million 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, 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 on line during the first seven months of our fiscal year.

In California, we have deferred our development program until oil prices improve and therefore we are 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 where the downside production -- protection of callers with a floor at $2.37. That leaves only 9% available for sale onto the spot market. But as always when we see opportunities we will layer in additional firm sales to minimize price related 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 close 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.

Karen M. Camiolo -- Treasurer and Principal Financial Officer

Thank you, John, and good morning, everyone. GAAP earnings per share were $0.47 for the third quarter, adjusting for items impacting comparability, including the ceiling test impairment charge recorded in our E&P segment, adjusted operating results were $0.57 per share, a decrease of $0.14 from the prior year. Strong 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 $0.10 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 6 Bcf of additional curtailments expected during the fourth quarter. These curtailments will have a corresponding reduction to throughout 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 enhance liquidity in advance of our December 2021 maturity. As it relates to the rest of our assumptions there were some movement of expenses between the third quarter 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 material increase in earnings per share when compared to fiscal '20. We are 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 related 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 million to $200 million in revenue for our Gathering segment. This is an increase of approximately $50 million from fiscal '20 or approximately 35% of 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 $0.08 to $0.09 per 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 recognized 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 million to $9 million increase in depreciation in the Gathering segment.

In our regulated businesses, we are expecting relatively flat earnings in 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 are forecasting a return to normal weather.

For the first nine months of fiscal '20 weather was 8% to 11% 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 costs. 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 to 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 on 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 the 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% to 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 dividends. Combining this with our anticipated cash-on-hand at 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 Appalachian asset, 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 debt refinancing.

With that, I'll close and ask the operator to open the line for questions.

Questions and Answers:


[Operator Instructions] Your first question comes from the line of Holly Stewart of Scotiabank. Your line is open.

Holly Stewart -- Scotiabank -- Analyst

Good morning, gentlemen, Karen.

Karen M. Camiolo -- Treasurer and Principal Financial Officer


David P. Bauer -- President and Chief Executive Officer

Hey, Holly.

Holly Stewart -- Scotiabank -- Analyst

Maybe first question for, John. Just, 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 a rally in 2021. We're starting to see that based on where '21 and '22 strip is heading. So just kind of wanted to revisit that topic and see where we go from here in terms of potentially adding capital back to the business?

John R. Pustulka -- Chief Operating Officer

Yeah, thanks, Holly. Actually, you're exactly right and to tell you the truth, we are approaching prices that makes sense. But once we get some visibility related to the online date of Leidy 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.

Holly Stewart -- Scotiabank -- Analyst

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

John R. Pustulka -- Chief Operating Officer

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.

Holly Stewart -- Scotiabank -- Analyst

Okay, great. And then 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?

David P. Bauer -- President and Chief Executive Officer

Yeah, actually it does improve. We're probably looking at a $0.10 to $0.15 per Mcf improvement, bringing on the new Shell assets compared to our current or our previous. So we get a 10% to 15% -- $0.10 to $0.15 improvement on that.

Holly Stewart -- Scotiabank -- Analyst

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

David P. Bauer -- President and Chief Executive Officer

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 calendar fourth quarter of this year. Then after that we would 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 and call out late winter and then full-on construction next summer.

Holly Stewart -- Scotiabank -- Analyst

Okay. Thank you all.

David P. Bauer -- President and Chief Executive Officer



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

Gordon Loy -- Raymond James Financial -- Analyst

Good morning all and thanks for taking my questions.

David P. Bauer -- President and Chief Executive Officer


Gordon Loy -- Raymond James Financial -- Analyst

I mean, just on -- a couple of 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 kind of bring online. Of those 32 wells, I guess, what's the DUC drawdown that's built into that?

John R. Pustulka -- Chief Operating Officer

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

Gordon Loy -- Raymond James Financial -- Analyst

Got it. That makes sense. And then my follow-up is, I mean, back when you guys announced the Shell acquisition, you guys had the slide just talking about having the base declines for Shell and Seneca were both in kind of below 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 the -- what kind of base decline is assumed for fiscal 2021 for the entire business?

David P. Bauer -- President and Chief Executive Officer

Yeah, absolutely. Currently, the Shell wells are around the 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.

Gordon Loy -- Raymond James Financial -- Analyst

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


[Operator Instructions] Your next question comes from Chris Sighinolfi of Jefferies. Your line is open.

Ryan -- Jefferies -- Analyst

Hey, everyone. This is Ryan [Phonetic] on for Chris. First, John, I know you touched on this a bit in your prepared remarks, but wanted to ask you about the capex guidance of $290 million 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 the 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.

John R. Pustulka -- Chief Operating Officer

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 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 differ 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, our fiscal first quarter, but that also move some capital from fiscal '21 into fiscal '20.

In terms of our per-unit costs, really the big driver there is the G&A, as I stated in earnings, we see about a $0.05 increase as a result of that. Like I said, we're increasing our G&A by 5% related to the Shell acquisition, but our production is increasing by well over 30%.

Ryan -- Jefferies -- Analyst

Okay, perfect. Sticking with costs we know it's 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 forcefully expense due to work stoppages or anything like that.

John R. Pustulka -- Chief Operating Officer

Sure. At the utility what we're seeing is some elevated expense related to the pandemic, right. So it comes in a couple of 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 an overall trend as Karen said in her remarks, it should be relatively stable maybe in that low single-digit inflation area, looking at -- 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 run rate going forward. Again, the second quarter during the winter is usually quite a bit higher, maybe 20% or 25% higher, but we wouldn't expect a big amount of cost to increase from our current baseline. In fact, hopefully if the pandemic calms down, we'll see a moderation in expense.

On the pipeline side there, we're looking at some timing issues as to how -- a couple of ways 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 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 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 million 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, but I'm happy to be more specific on it, if I can.

Ryan -- Jefferies -- Analyst

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.

Karen M. Camiolo -- Treasurer and Principal Financial Officer

Yeah, so we're not expecting to be in a cash tax paying position next year. Next year, no.

Ryan -- Jefferies -- Analyst

Okay, perfect. That's all from 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.

Kenneth E. Webster -- Director of Investor Relations

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 14. To access the replay online, please visit our Investor Relations website at 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.

Duration: 37 minutes

Call participants:

Kenneth E. Webster -- Director of Investor Relations

David P. Bauer -- President and Chief Executive Officer

John R. Pustulka -- Chief Operating Officer

Karen M. Camiolo -- Treasurer and Principal Financial Officer

Holly Stewart -- Scotiabank -- Analyst

Gordon Loy -- Raymond James Financial -- Analyst

Ryan -- Jefferies -- Analyst

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