Q3 2020 National Fuel Gas Co Earnings Call
All participants are in a listen only mode. After the speakers presentation. There will be a question answer session to ask your questions. During this session you'll need to press star. These advised that today's conference is being recorded if you require further assistance. Please press star Zero I would now like to hand, the conference over to your Speaker today 10, Webster director of Investor Relations. Please go ahead Sir.
Thank you Brian and good morning, we appreciate you joining us on todays conference call for a discussion of last evening's earnings release.
Thats on the call from National fuel gas company, our Dave Bauer, President and Chief Executive Officer, carrying cameo low 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.
Third quarter fiscal 2020 earnings release and August Investor 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 fuel to expectations beliefs, and projections are made in good faith and are believed to have a reasonable basis Billy.
These statements speak only as of the date on which they are made and you may refer to last evening's earnings release or 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, Thanks, and good morning, everyone.
As with most in oil and gas companies.
Commodity prices weighed on the third.
Gathering business.
However, the remainder of the system at 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 all told the quarter was another good diversified model where there.
Earnings and cash flows of our regulated businesses provided a strong measure of stability against the more variable earnings.
Operationally this was there.
Really significant quarter for national fuel wondering which we reached several important milestones that make us well position.
And to deliver meaningful growth in the years to comp.
First and foremost last week, we closed on the acquisition of shells upstream.
In midstream properties and Appalachian.
This is a terrific opportunity that we're in an acquisition.
From start to finish it was the result dozens of employees across our upstream and midstream operations.
Okay.
The acquisition.
Asia in fact earlier this week Senecas gross natural gas production crossed the one bcf per day threshold.
Great milestone rent to put in perspective.
Active in fiscal 2018, our average daily production was only about half now.
With the added scale. We can you can see that in our guidance on cash operating costs, which we expect will be down about five cents per M. Cfd and 21 for the transaction is complete.
Kudos to our finance team in the banks that supported them, we're getting the deals done 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 objective.
In may.
We issued $500 million a bond we're used to fund the debt component of the acquisition.
We also raised just on.
Sure $175 million, we've done is a better price than we would have received under the equity backstop arrangement.
Salable to us under the shell per and lastly earlier. This week, we signed an agreement to divest substantially all of our Appalachian timber properties for approximately 160.
Seen million dollars, which will fund the transaction.
The timber properties or a non core.
The earnings and cash flows associated with them are modest in fact pretty close to breakeven.
Reinvesting the proceeds from the sale allows us to avoid issuing and other.
At the midpoint or of our fiscal.
That saves approximately eight cents per se.
In addition, the timber properties have a very low tax basis by.
For the timber sale ends and shelf.
Age and by doing so differ a large tax gain.
The remainder of Senecas operate.
Patients continue to run smoothly Paul.
But I'd like to emphasize the improvement we expect in this business in fiscal 21.
The midpoint of our production guidance.
Is 320 Bcf fee.
A 32% increase over it.
Honey.
In addition.
To 65 to 275 area Theres 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 has had.
These factors should cause cash from operation.
Tends to grow meaningfully.
Moving to a single rig program.
Stream is expected to decrease.
First or about 25%.
So putting it all together assuming the current strip next year, we expect more than $150 million and free cash flow from our NP in gathering business.
Fine in storage segment is also positioned to deliver meaningful growth in 2000.
Several noteworthy events occurred during the quarter to help make that a reality.
We placed a portion of our Empire North project in the service ahead of schedule, which allows us to capture some modest short term growth for 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 an annual revenues.
In July we received our FERC certificate for the F. Am 100 project in France will also receive their FERC approval for the companion Lighty South project.
Both projects are on track for a late calendar 2021 in service date.
As a reminder, the expansion portion of this project is expected to add $35 million an annual revenue.
Lastly in early June FERC approved the settlement of supply corporations 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 an annual revenues.
Settlement also addressed the rate, making treatment of the modernization component of the F. I'm 100 project.
On the later of the answer.
2022, a step up.
Adding an incremental $15 million 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 or 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 unregulated 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 answer, Pennsylvania service territories for.
Our capital program has returned to pre pandemic levels.
We continue to focus on modernization projects that enhanced 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 to at our utility for at least the next few years.
Lastly, a few words on the cobot 19 pandemic.
Thankfully infection rates have been relatively moderate in Western New York in 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 ERP and our practicing social distances.
It's been incredible effort by our employee group to get US, where we are today and I'd like thank all of them for their hard work 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 today.
Our balance sheet is strong 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 Fiftyth 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 were excited to move forward after successfully closing on the acquisition of shells 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 senecas cost structure.
And to put this into context, our GNS expense as a result of the shell acquisition is expected to increase less than 5% in fiscal 2001.
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're working towards maximizing the upside as we integrate these assets into our overall development plan.
We have now at a 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 today, a firm transport on National fuels Empire system, and a 100 million today on Dominion.
In fact, as a result to this dominion capacity, which provides access to lighty hub senecas into unique position of being able to flow production from each of its three major producing areas into its FM 100 lighting sales capacity.
Moving forward, we work closely with our midstream group to determine how to best integrate our development pipeline activity, then 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 Bcf fee, 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 the have since curtailed an additional two bcf for 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're now forecasting to curtail our.
Remaining spot volumes for the rest of this fiscal year.
While pricing and related curtailments put a damper on Sonic as result 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 improve 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 584000 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 the remainder of the year at an average price of about $60 per barrel, 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 240 245 Bcf fee.
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're currently planning to remain at a one rig pace in Pennsylvania.
Due to our lower activity level with only a single Reg 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 Bcf fee of 32% increase versus fiscal 20.
This increase is driven almost entirely by the production acquired from show.
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 spend around $10 million and 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'll move to quickly returned 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 from 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 production protection of collars with a floor at $2.
37 cents.
That leaves only 9% available for sale on to the spot market.
But as always when we see opportunities we will layer in additional from 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 care.
Thank you John and good morning, everyone.
GAAP earnings per share were 47 cents for the third quarter adjusting for items impacting comparability, including the ceiling test impairment charge recorded in our E. M. P segment. Adjusted operating results were 57 cents per share a decrease at 14 cents from the prior year.
Strong results from our pipeline and storage segment did the impact of the supply rate case.
Lower operating expenses were more than offset by lower natural gas and oil price realizations.
Last nights 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.
These changes due to a field 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.
He's curtailments will have a corresponding reduction to throughput in the gathering segment.
From a pricing perspective, we've revised our Nymex gas and WT oil assumptions, but given our strong hedge position. These changes generally offset each other from an earnings perspective I.
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 and then in advance of our December 2021 maturity.
As it relates to the rest of our assumptions there was some movement up expenses between third and fourth quarter and I regulated subsidiaries, but substantially all of our other guidance items for fiscal 20 remain intact.
Looking forward to fiscal 2001, we're expecting material increase in earnings per share when compared to fiscal 20.
We are initiating preliminary guidance in the range of 3040 cents to 3070 cents per share an increase of nearly 27% at the midpoint.
This range excludes the impact if any future ceiling test impairments, which we expect to incur in the fourth quarter. This fiscal year as well as the first quarter fiscal 21 based on the forward curve as of today.
Our fiscal 21 pricing assumptions and hedge positions are outlined in last nights 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 10 cents change in natural gas prices is expected to impact earnings by 11 cents per share a five dollar change in oil by four cents per share.
The biggest driver of the year over year earnings increase relates to the impact of the shell acquisition in both the NPM gathering segments.
Production is expected to be up nearly 80 Bcf the 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 as expected to lead to a $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% at the midpoint <unk>.
A portion of this revenue growth will be offset with slightly higher expenses related to the acquisition, where we now expect going on expense in the segment to be approximately eight to nine cents per mcf the of growth gross throughput.
This is driven by higher.
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 I went on 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 eight to 9 billion dollar increase in depreciation and the gathering segment.
In a 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 returned to normal weather for the first nine months of fiscal 20, whether with 8% to 11% warmer than normal across our service territory. This reduced margin by about.
$5 million them that the majority of which was within it and our Pennsylvania service territory, where we do not have a weather normalization clause.
In addition to normal weather, we're 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 physical 21.
Selling and the other direction is a modest 1% to 2% increase in Ireland and expense inline 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 recap re contracting that happens in the normal course of business as well the reduction in short term contracts, which we don't assume to recur.
On the expense side, we expect own 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 did 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 and 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 an excess of $100 million and 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 refinanced the acquisition of shelves Appalachian assets.
We 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 upsize 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 your question over the phone. Please press Star then one on your telephone keypad, we will pause for a moment to compile the today roster.
Your first question comes from the line of Holly Stewart of Scotiabank. Your line is open.
Good morning young hearing.
Hi, Alex.
And let me first question for John just Yeah, I know we've talked about this on <unk> on past calls, but just as you think about.
The activity level I know you 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 were 21 and 22 strip is heading so just you kind of wanted to revisit that topic and he where we go from here in terms of potentially adding cap.
Go back to the business.
Yeah, Thanks, Khalid actually you're you're exactly right and tell you. The truth, we are approaching prices that makes sense, but to too, but once we get some visibility related to the on light days, though like yourself I think we would certainly consider adding back that segment rig a few months.
Prior so we are already looking at that honestly, though right now it's still doesn't make sense to add a rig just to produce into the spot market. It has to be tied to too as we grow into these opportunities to get our gas into some premium markets, but we are this definitely something we're evaluating as we speak.
Okay, and <unk> and as you think Apollo to that I guess as you think about that would that rig go to work in the EPA.
That's it most likely would we're thinking Tioga first and then moving where we needed we will move the rig after that where we need it.
Okay, Great and then yeah, maybe just thinking about the overall SP capacity, you've got the new shell capacity that's come on your existing portfolio and then the S. In 100 projects. So.
I'm, assuming you're end market exposure shift a bit and actually probably imprinted. So how should we we think about this changes to end market.
Yeah actually it doesn't improve we're probably looking at a 10 to 15 cents per Mcf improvement, bringing on the new shell assets.
Compared to our to our current or our previous so we get a 10 to 15 or.
10 to 15 cents improvement on that.
Okay, and then that's great and then maybe just one more for me if I take on that on the pipeline side that the M. Jasmine ones into 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 we didn't see any issue is with put the.
The various P.A., a environmental a agencies and the Army corps have to work through that process and we'd expect that in the sort of calendar fourth quarter of of this year. Then after that we we would request to a notice to proceed which we would expect FERC to grant in short order and then we'd we'd.
To begin construction likely with tree clearing and and caught up late winter and then pull on construction next summer.
Thank you all yep.
Your next question comes from the line of Court in light of Raymond James Your line is open.
Good morning on thanks for taking my questions morning.
Yeah, I mean, just on a couple of questions John I'm looking at the call it 300 million in them.
GMP capital for fiscal 2021, and then I'm going to be a 32 wells that you guys trying to bring on line.
Those 32 wells.
I guess, what's the Doc draw down that's built into that.
Yeah, actually we're going to be drilling 23 wells total.
And completing 40.
So yeah, we're will be certainly completing more wells and we're drilling we're bringing those 32 on and currently where the Doug town I think it's around 19 right now 18 to 20. So we will certainly burn then to that DUC count over the next 12 months.
Got it that makes sense and then my.
My follow up is.
Let me back when you guys announced the no show acquisition you guys had this slide.
I was talking about.
Having the base declines for selling cynical about kind of low low 20% and then the.
Expectation was that the show asset base decline would decline to sub 20%.
Being I guess I just wanted to see if I could get to update on I know where.
Go straight declines on kind of what yeah.
What kind of base decline is assumed for fiscal 2021 for the entire business.
Yeah, absolutely yeah currently the the shale wells are on or around the 20% decline so pretty much in line with what were thinking and our Seneca add on so all in including the Seneca assets were looking at maybe 20% to 22% base decline.
Got it that's helpful. Oh go ahead. Thank you.
Okay, and if you'd like to asked a question over the phone lines. Please press Star then one on your telephone keypad Euronets question comes from Chris signal fee of Jefferies. Your line is open.
[noise] everyone listening Ryan on for Chris first John I know you touched on that's been in your prepared remarks, but wanted to ask you about the Capex guidance of 290 to 330 million I believe on last quarter's call you get a Soc I've got to 59. So I'm just wondering what's changed if there's anything initial acquisition that would be driving capital efficiencies.
Absolutely we notice 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.
Our costs, our drill efficiencies have 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 a completion as well so we've been able to drive down costs as a result to that so that's one of the movers. Another reason for it is earlier this year, we had drilled for.
Utica wells and double a seven 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 we're currently completing those wells.
And we should see those I'm thinking that will come online later first quarter fiscal first quarter.
But that also moved some capital from fiscal 2001 into fiscal 20.
In terms of our per unit cost really the big driver. There's the Gionee as I stated in earnings or we see about a five a five cents increase as a result of that like I said, you know, where we're increasing our DNA by 5% related to the shell acquisition, but our production is increasing by well over there.
30%.
Okay, perfect sticking with costs, we notice a relatively large step up and olin and at the utility there's a pretty steep drop off a pipeline and storage business. So just curious sort of you know what was going on at the utility and if there was anything that would typically be capitalized, but what was then and then of course the expense due to.
Yeah work stoppages or anything like that.
I'm sure the where it at the utility I know what we're seeing is a is some elevated.
Expense related to to the pandemic right. So we it comes in a couple of forms one is a is higher pp.
For the the folks out in the field on one hand, and then in the in the second quarter, we had a a dynamic where and I guess I suppose to an extent in the third quarter as well, where oh, because a part of our workforce was idled or the the cost of that labor was hitting on M. A as opposed to being.
Capitalized because the the that contingent would normally be working on capital projects, so that that boosted oh and I'm expense I'm a bit.
When you look at an overall trend as Karen said and.
In her remarks, it should be relatively stable you know maybe in that low single digit a inflation area. You know looking at it tends to be except for the second quarter. It tends to be pretty stable. So the third quarter, a notional oh and I'm rate is probably a good proxy for.
On run rate going forward.
Again, the second quarter during the winter is a is usually quite a bit higher you know, maybe 20 or 25% higher but we wouldn't expect.
A big amount of of cost increase Oh from our current baseline in fact, hopefully with <unk> if the pandemic a calms down we'll we'll see a moderation in expense.
On the pipeline side.
There were looking at some some timing issues as to how Oh, Okay. A couple of ways our expenses fall between quarters on the one hand.
And then when you look at at our our compressor overhaul work out sometimes we're able to capitalize those costs. If the jobs are really big other times, we have too expensive and we've got this dynamic where where last year. We had a lot of oh in EM compressor work in this year it because it happens to be more capital so you're.
I get that that dynamic I think when you you you consider pipeline going I'm looking at the last you know Cook trailing 12 months is probably a good proxy for a baseline.
But then add to that.
I'd say you know somewhere in the you know maybe $2 million to $3 million related to the the growth that we've seen particularly the the Empire North project and then as we we begin to hire people to the staff the a compressor stations and the a and a 100 project. So so that's a really long answer.
That I'm happy to.
To be more specific on it if I again.
No no that was great. Thanks, Thanks for all that and just one last one if I could Karen I know you mentioned that you didnt expect to a need additional financing and fiscal 21 out of that was not as one of my questions, but I'm just an update on a cash tax expectations next year, if you could yeah yeah.
So yeah, we're not expecting to being a cash tax paying position next year.
<unk>.
Next year now [laughter], Okay [laughter].
There are no further questions over the phone lines at this time I turn the call back over to 10 Webster for closing remarks.
Thank you and 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 web site and by telephone and will run through the close of business on Friday August the 14th to access the replay on line. Please visit our Investor Relations Web site at Investor Dot National.
Fuel gas dotcom and to access by telephone call. One 805, 858367 and enter conference I'd number 90862 to three this concludes our conference call for today, Thank you and goodbye.
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