National Fuel Gas Company (NFG) Q4 2019 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by and welcome to the National Fuel Gas Company Q4 2019 Earnings Conference Call. At this time all participants are in listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. [Operator Instructions] I would now like to hand your conference over to your speaker today Ken Webster, Director of Investor Relations. Please go ahead sir.

Thank you, Marcella, 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 fourth quarter fiscal 2019 earnings release and October 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 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. With that, I'll turn it over to Dave Bauer.

Thank you, Ken, and good morning, everyone. National Fuel ended its fiscal year with a strong fourth quarter. Record production at Seneca and its corresponding impact on our Gathering segment offset the impact of lower realized natural gas prices and contributed to a 10% increase in year-over-year consolidated operating results. Operationally, we had a really good quarter across the system. Seneca brought on two new pads, one each in the EDA and WDA. Both pads exceeded our expectations. Cash unit costs were down meaningfully year-over-year, a trend we expect will continue as Seneca's base of production grows. Seneca is currently operating 3 rigs in Pennsylvania. As I said on last quarter's call, we plan to release one of those rigs once it's done drilling a 6-well pad in Tioga County, which should be some time in the middle of our second fiscal quarter. I expect we'll stay at that reduced level of activity for the near future. Even at a 2-rig program, Seneca will see production growth of nearly 15% next year and single-digits the following year. Any further activity changes will obviously be dependent on pricing. As we move through the winter season, we will continue to watch prices and reassess our activity level for 2021 and beyond. Seneca's operational success continues to directly benefit our Gathering segment, which, on the strength of record throughput, saw revenue growth of approximately 18% over last year. We expect future Gathering throughput will grow in lockstep with Seneca's production, which should translate into annual revenue growth of approximately 10% on average in the near term. Owning 100% of the Gathering infrastructure that supports Seneca's operations gives us a significant economic advantage. We have attempted to highlight that in the updated IR deck that's available on our website. In it, you'll see that we're now disclosing consolidated upstream and Gathering returns for each of our major producing areas. These returns are quite attractive. Even at a $2 netback price, we realized consolidated returns in the range of 25% to 60%. John will get into a little more detail on this in a few minutes, but I'll point out that 60% of our forecasted 2020 production is already locked in above that level at a $2.30 netback price. Moving to the regulated businesses, today, we placed in service our Line N to Monaca project, which ties our supply corporation system to Shell's $6 billion petrochemical facility in Beaver County, Pennsylvania. As a reminder, this approximately $24.5 million investment will add about $5 million of annual revenues. Construction of the Empire North Project, which has an in-service date in the second half of fiscal 2020, is progressing right on schedule. On our supply corp. system, the FM100 project is moving through the regulatory process without any major issues or surprises. Once in service, together these two projects will add about $60 million in annual pipeline and storage segment revenues. Supply Corporation's rate case is proceeding according to schedule. You'll recall, we filed that case to satisfy both the comeback requirements from our previous rate settlement and the FERC's federal income tax proceeding. Data requests are being exchanged among the parties and settlement discussions should commence by December. We have a good history of settling for rate cases, and I'm optimistic we'll do so with this case. At the utility, we continue to make investments in modernizing our distribution system. We spent approximately $74 million on safety and reliability upgrades this year and expect to invest a similar amount next year. This investment, which is supported by a system modernization tracker mechanism in New York, is a win-win for the company and customers and that it allows us to further enhance the safety and reliability of our system, while recovering the cost of that investment on a timely basis. In addition to modernization-driven rate base growth, we continue to see modest customer expansion in our New York Service territory. The improved local economic conditions in Western New York, combined with continued low natural gas prices, are the principal drivers of this growth. We expect this trend will continue in the near term, a clear sign our customers value natural gas as an efficient, cost-effective way to heat homes, notwithstanding the state's view towards pipelines and fossil fuels. While it's easy for policymakers to say we ought to switch to 100% renewable energy, actually doing it isn't quite as simple, especially when you consider the cost to consumers making such a switch. We intend to be an active participant in state energy policy discussions to ensure that our 500,000-plus customers in the state continue to have access to low cost, reliable energy. In closing, it was a good quarter and a good fiscal year for National Fuel. Looking to next year and beyond, I'm confident that we can build on our success. Seneca has a sizable inventory of drilling locations that are highly economic, even in a low gas price environment. And pricing for next year is largely secured by hedging and marketing portfolios that reach premium markets in the Atlantic and Canadian markets. The production from our wells will drive growth and returns not just at Seneca but at our Gathering business as well. On top of that, our regulated companies have a great backlog of expansion and modernization opportunities, which should contribute higher earnings and support the continued increase of our long-standing dividend. In short, our diversified business model makes us very well positioned to deliver value for our shareholders. With that, I'll turn the call over to John for an update on Seneca's operations.

Thanks Dave and good morning, everyone. Seneca had a strong fourth quarter. We produced 59.1 Bcfe, an increase of around 25% compared to last year's fourth quarter. Total annual net production came in towards the high end of our guidance at 211.8 Bcfe. Again, a new high for Seneca and around a 19% increase year-over-year. As of fiscal 2019, we have now produced over 1 Tcf of gas from our shale acreage in Pennsylvania. For the year, capital expenditures and expenses on a per unit basis were all within our guidance ranges. Proved reserves increased by almost 600 Bcfe or 23% to 3.1 Tcfe. Our proved developed reserves now make up approximately 67% of our total reserves. And we continue to reduce our three-year average F&D cost, now at $0.56 per Mcfe. We have posted an updated Marcellus and Utica type curves for all of our production areas in our Q4 investor deck, including an updated WDA Utica development type curve on Page 20. As a reminder, our initial Utica type curve was based on our first five appraisal wells in the CRV area. Our updated development type curve is based on results to date for all 26 wells online in this area. This type curve ranges between 1.6 Bcf to 1.7 Bcf per 1,000 foot and assumes all wells going forward are bounded and spaced around 1,200 feet apart. Our latest Utica pad, located to the Southeast in Rich Valley, has now been online for over three months. Four out of the five wells on this pad are performing above our type curve and on a per-well average is our best to date in the WDA. Including this pad, we are now producing from 11 wells along the southern boundary of the CRV area, with 10 of these wells producing above our updated type curve. If this trend continues, as we move to the south from the CRV area across our acreage position towards Boone Mountain, we may introduce a second Utica type curve to better portray the positive results we're seeing along this corridor. We need to bring online additional pads in this area, however, before we're comfortable adding that second curve. With respect to our WDA Utica drill and completion design, we have not seen much difference in terms of production between the Lower Utica versus the Upper Point Pleasant. Of the 26 CRV wells brought online to date, our best performers utilized drawdown management and were completed with a produced fluid blend of less than 95%. We will continue to employ a conservative drawdown management plan to reduce issues related to proppant embedment and crushing, and we'll take an active approach to ensure consistent fluid blend percentages across stages for each well. In terms of completion intensity, the larger designs utilizing higher proppant loading and tighter stage spacing have resulted in higher production on a per well basis. But it's a bit too early to determine if that translates into improved economics. In California, we produced 610,000 barrels of oil during the fourth quarter, an increase of around 6% over the third quarter. This increase was due primarily to our recent drill activity at Pioneer located near our South Midway Sunset field. We brought online 13 new producers in July and August, and these wells averaged around 500 barrels per day of net production during the fourth quarter. And finally, our 17N section, located near our North Midway Sunset field, continues to produce just over 400 net barrels per day. Moving to our fiscal 2020 guidance, our capital expenditures and production range remain the same. Production growth forecasted to be up around 13% at the midpoint year-over-year should occur primarily during the second and fourth quarters as we bring on new pads with a moderate decline during both the first and third quarters. In September, when NYMEX prices rallied, we were successful in adding another 20% layer of fiscal 2020 hedges at an average price of $2.54. As a result, we now have locked up around 136 Bcf, around 60% of our fiscal 2020 East division gas production, physically and financially at a realized price of $2.30 per Mcf. We have another 60 Bcf of firm sales providing basis protection, so over 87% of our forecasted gas production is already sold. We currently estimate that we'll have around 28 Bcf of gas exposed to the spot market, so these volumes are potentially at risk for curtailment. Already in October, we experienced several days of very low in-basin prices, and we elected to shut in spot production totaling just over 0.5 Bcf. Finally, in California, around 70% of our oil production is hedged at an average price of just over $61 per barrel. And with that, I'll turn it over to Karen.

Thank you, John, and good morning, everyone. Last night, National Fuel reported fourth quarter adjusted operating results of $0.54 per share, an increase of $0.05 or 10% over last year. The majority of the earnings growth was driven by our nonregulated operations, where the 12 Bcfe year-over-year increase in Seneca's production and the associated Gathering throughput more than offset lower realized natural gas prices. Like any quarter, there were a number of smaller moving pieces, but the earnings release does a good job describing those drivers. The one item worth noting is our effective tax rate for the quarter, which came in at 19.4%, which was below our expectations. The fourth quarter can see some movement year-over-year on our effective rate as we true-up some annual accounting estimates. This year was no different. While I'm at subject of taxes, as a reminder, the enhanced oil recovery credits phased out at the end of fiscal 2019. And as a result, our effective tax rate is expected to increase to approximately 25% for fiscal 2020. Looking to next year, we are revising our fiscal 2020 earnings guidance down to a range of $3 to $3.30 per share. This is principally driven by three main factors. First, we are reducing our natural gas price assumption to $2.40 per MMBtu, down $0.15 from our preliminary guidance. This drop is partially offset by the incremental hedges that we added during the quarter. While our price deck is generally in line with the future strip, for reference, every $0.10 change in NYMEX is approximately $0.05 in earnings per share for the year. We are also revising our expected Midway Sunset oil price premium from 108% to 106% of WTI based on recent realizations in California. The second main item relates to an expected increase in operating expenses mainly related to noncash pension and postretirement benefit expenses. Since our last earnings call, interest rates fell meaningfully, such that our final actuarial assumptions reflected lower discount rates and a reduction in the forward-looking asset return assumptions than was previously forecasted. As a result, we are now expecting pipeline and storage O&M and non-service pension costs to collectively increase 4% to 5% from fiscal year 2019 level, while similar costs in the utility are expected to collectively increase approximately 3%. With regards to the increases related to the pipeline and storage benefit costs, as Dave mentioned, we are currently in a rate case with Supply, where we expect to recover in rates the funding of these benefit plans. The last main driver of our earnings guidance decrease is related to Seneca’s DD&A rate, which is up $0.025 at the midpoint from last quarter’s preliminary guidance. This is principally driven by an increase in our full cost pool plugging and abandonment liability in California. There, we are part of an ongoing statewide effort to reduce the number of outstanding idle wells at a faster pace than before and using more stringent plugging requirements mandated by the state. On top of these incremental requirements, service costs for plugging crews are increasing due to the demand to meet the statewide initiative. As a result of this assumed increase in plugging and abandonment costs per well, our asset retirement liability has increased meaningfully. In addition to driving our DD&A rate higher, we also will see higher ongoing accretion expense during the year. Other than the items I just mentioned and some minor revisions to our E&P unit costs, the rest of our guidance remains unchanged. One item I wanted to clarify from our previous guidance, we expect property taxes in our pipeline and storage segment to increase approximately $2 million in fiscal 2020 relative to the 2019 level. This is primarily a result of a scheduled phaseout of a multiyear tax incentive negotiated with certain jurisdictions when the Empire Connector project was constructed in 2008. Over the coming years, we’d expect further phaseouts in other jurisdictions, driving additional property tax increases in this segment. With respect to capital spending, our fiscal 2020 guidance remains the same at $725 million to $820 million. At the midpoint, this represents a slight decrease from our fiscal 2019 spending. From a financing perspective, we ended the fiscal year with a modest amount of short-term borrowings outstanding. As we look into fiscal 2020, with the ongoing construction of the Empire North project along with our other financing requirements, we expect our full year incremental borrowings should be around $200 million for the year. With this in mind, we now forecast interest expense to be in the range of $105 million to $110 million. We have ample liquidity under our $750 million credit facility and that will be our primary avenue to fund this outspend. Our next long-term maturity is still two years out, so we don’t have a pressing need to be active in the capital markets. This being said, we always remain opportunistic. And with the steep drop in interest rates, we continue to evaluate all of our options. In conclusion, we are in a good spot financially. We have significant liquidity. Our investment-grade credit rating has a stable outlook, and we have no near-term debt maturities. This, along with a strong hedge book, puts us on solid footing to navigate a challenging commodity price environment. With that, we can turn the call over to the operator for questions.

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

Good morning.

Hi, Holly.

Maybe the first one, just high level, either Dave or John, just kind of thinking about the comments around having the flexibility to reduce capital spending to Seneca on pricing or related to pricing, if need be. Just can you give us a little color around that comment? I guess, given the hedge book, do you – is this a multiyear lookout? Like, how do you think about the weakness in pricing and your reaction to that?

Thanks, Holly. Our current plan is to drop a rig during the fiscal second quarter. Obviously, that's being driven to reduce our spot exposure at the current script. That rig is currently drilling Utica wells in Tioga. And as we move into the winter season here, we're going to continue to watch and see how prices go. If we're successful in layering in additional firm sales, then that may postpone the chance or the potential drop in that second rig. But at this stage, I think we'll just wait to get to the winter season and then reevaluate at that point whether or not it makes sense to drop another rig.

Okay. And then maybe a follow-on to that, John, would be do you have a level of spending, I guess, that you would think about as kind of maintenance capital? And then is there an associated rig count or well count that we would think about then to kind of hold production flat?

Yes. For us to hold production flat, we've calculated and looked at this before. It's between a 1-rig to 2-rig case, a spend about $250 million to $300 million a year. So at 1 rig, I don't think we'd be able to hold it flat. But certainly, if we're back and forth between 1 to 2 rigs, we can do that.

Okay. That’s super helpful. And then maybe just, John, any incremental color you could provide on the CRV Utica EUR? It looked like it modestly went down even though the laterals appear to have increased?

Yes. It modestly went down on a per foot basis. But honestly, we expected that. Our first five wells were unbounded appraisal wells. Now we’re drilling – each pad that we go to, we’re drilling multiple development wells. Our spacing is about 1,200 foot. So we expected to see a little bit of a decrease now that all of these wells are bounded. So it really wasn’t that big of a surprise to have a slight deduction.

Okay. That’s great. Thanks, guys.

Your next question comes from the line of Tim Winter from Gabelli. Your line is open.

Good morning, and thanks for taking my question. I have sort of a big picture strategic question that follows up on that first one. So the Utility had a nice year, $0.70 a share earnings. And if you look small gas utilities trade 25x earnings, which gets you about $18. Pipeline and storage, Gathering earned $1.52. If you just conservatively put a 15 multiple on that, you’re at about $23. So summed up, you’re at $41. And with NFG at $44, it seems like you’re not getting full value or much value at all for Seneca, but the capital budget of $800 million has about 60% allocated to Seneca. I’m just wondering if you guys are considered buying more regulated assets, like maybe even into the electric or water distribution business?

Yes. Hi Tim, our focus in the near term is on our natural gas opportunities and that’s across the value chain, right? So we’ve got the opportunity to grow the pipeline business in a meaningful way and our existing utility in a, I'll call it, more of a modest way. The returns on the wells that we're drilling, as I said in my remarks, are quite good when you look at it on a consolidated basis. So we feel good about our program. When we think longer term and bigger picture about other directions we might take, I mean, certainly, acquiring other regulated assets, whether they be electric, water or gas are certainly avenues that we could pursue amongst many different ones. As with anything, we got to compare our return potential for what we buy with what we already have. And these are things that we routinely evaluate and discuss with the Board.

Okay, great. Thank you

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

Good morning and thanks for taking my question. So I was just looking at Slide 58, kind of where you guys give all the Seneca economics. And I recall in the last – around this time last quarter when we were having the call that the two rigs that are remaining will be located in the WDA. And I was trying to reconcile, just trying to figure out if there's any other factors that you guys had in terms of choosing to allocate the remaining rigs in the drilling program going forward to the WDA instead of to the EDA?

Yes. Sure. Honestly, a rig in the EDA with continued activity there would generate volumes that would have to be sold in the spot market. And at the spot market if prices are poor, obviously, that just wouldn't make a whole lot of sense. Our spot pricing at our receipt point and the WDA has historically ranged between $0.10 to $0.30 better than we see at the EDA sales points at TGP Zone 4 and also in Leidy. And almost all of our activity in the WDA is focused currently on return trips to existing pads with existing infrastructure, which significantly enhances our consolidated economics. We also view a 2-rig program there will allow us to grow into our FM100 Leidy South commitment, which is currently scheduled to come online late in 2021. So that's really the driver of why we have the two rigs from the WDA.

Okay. That's extremely helpful. And I guess, my one follow-up and just kind of a simple clarification question. The return metrics located on Slide 58, they all include factoring in the NRI for the EDA, right?

Absolutely.

Okay. That’s all I had. Thanks for taking my question.

Your next question comes from the line of Chris Sighinolfi [Jefferies LLC]. Your line is open.

Hey, good morning everyone.

Hey, Chris.

Hey. I appreciate all the color this morning as always. I think I have a question for each of you, if I could. Karen, I guess, to start, I appreciate the color on the drivers of earnings tax impacts in 4Q and the change from 2019 to 2020. I'm curious if you have an anticipated cash tax rate you could share? I think the initial expectation a while ago was for modest refunds in fiscal 2019 and 2020, given some ATM usage or credit usage, but I don't know with the passage of time any updates to your plan if that's still a good base.

Yes. So we're still in that position.

Okay. I guess, you had said net financing, you thought, would be $200 million. So I guess I could just back into what that implies, but it was implying a positive number for me. So I just wanted to confirm that.

Yes. That’s very correct.

Okay, thanks for that. And then John, if I could switch and follow up on just the last questioner to better understand the calculation that you've embedded in those consolidated IRRs for Seneca, including Gathering. You note in the footnotes there that Gathering CapEx included is for expected remaining return trip locations. I guess I have an impression of what that means, but I think safer just to ask you what that means. What does that mean? I guess what is included versus excluded in regard to Gathering CapEx?

Yes. It’s all in there. Chris, it's all included.

Okay.

I think it's – all of the Gathering is included in those economics on our return trip actually for all of it.

Okay. So, this – I guess, the sunk cost if you're going to reuse Gathering infrastructure that was predicated for the Marcellus development originally and it gets reused or recycled for Utica development now, how – I guess, is that viewed in the sunk cost and therefore not applicable in the calculation, because it's looking forward? Or do you carve that up and share?

Yes. Now, we look at it on a point-forward basis.

Okay, understood. And that’s what I wanted to make sure. Okay. And then finally, I guess, Dave, for you, there's heightened media focus on utilities and the environment. I mean, if we look at what's going on in – with PG&E in California and the drama between national grid and the PSE and Governor Cuomo here in New York, I'm just curious, with the CLCPA passed earlier this year, what things NFG can do or is doing to prepare for the impacts of that, recognizing, of course, the targeted goals of some years in the future.

Yes, sure. What we're really in the early stages, so it's a little early to say what the exact impact is going to be. This is a process that's going to play out over a few years. The first step is the appointment of a Climate Action Council by January of next year. And then after that, there's four years of process to get any sort of regulation in place. We intend to be an active participant. Donna DeCarolis, who you know is the President of our Utility, was appointed to the Climate Action Council, which is the main committee that will be overseeing the process. So we'll have a seat at the table and be able to keep everyone up to speed as we move through time. But I think, long run, there's definitely going to be a role for an LDC in our service territory. When you just consider a few facts, we serve 95% of the heating load of the customers in our service territory. Our reliability is better than 99.99% or a cold climate better than 75% of the days have temperatures below 30 degrees, and heating with electricity is pretty expensive, as much as four times as expensive is with natural gas in our service territory. So when you overlay this so that we're not necessarily a rich community. The median income in the city of Buffalo is less than $40,000. I think it's pretty hard to see the LDC going away if cost and reliability are factors that will ultimately enter the equation.

And that's part of the Climate Action Committee's mandate is to consider those items as well. I mean, it's my hope, but I'm asking.

Yes. As I understand, the cost benefit is a definite factor. You got to understand, Chris, that this was – if you read the legislation, it basically sets targets and then says, we’re going to – they’re going to set up committees to figure out how we’re going to reach those targets. There’s not…

That is what I noticed. So it’s just – and it feels like having read Governor Cuomo’s letter to PSC about the supply shortage that national grid is talking about. I mean, it’s just – it feels like the Utility is saying we wouldn’t have this problem if you had approved the pipeline, and the Governor’s saying, you have a problem that you didn’t plan for, and it’s your fault. And so, I guess, when you contrast that or compare that against legislation that has defined goals but no defined path, I just worry about anybody getting caught up in that. That’s what sort of prompted the question. And I saw a release you guys put out a couple of days ago about Niagara Falls for zero-net energy home, which you had a role to play in. And I’m just curious like things like that, are they scalable? Is that how NFG distribution sort of fits into the pie?

Yes. I mean, those are all things that we’re exploring. And again, I think the – when you consider the reliability and you consider the cost savings from natural gas, it’s really hard to see how electrification of heating loads in Western New York makes sense for the consumer.

Yes. Okay. All right. Thanks a lot for the color this morning. I appreciate it.

You bet.

[Operator Instructions] Your next question comes from the line of Sam Monnier from G Research. Your line is open.

Hi. Good morning. Thanks for taking my question.

Good morning.

I’m new on following the Appalachian E&P names and of course your company. Can you walk me to the economics of a well? First, how much it costs a drill when completed? And then secondly, using the net gas prices at the current strip, what's the return of the well, just the well, excluding the gathering system?

Yes. If you go to our slide deck on Page 58, all of that information is on there. And as far as the Seneca standalone, our economics are on the footnote on that exact same slide. So it'll go through the costs, the average costs across each of our producing areas. It will give you an average EUR per 1,000 foot and it also will show you our economics both on a standalone and also on a consolidated basis.

Okay. I mean, since you provide CapEx on per 1,000 foot. What’s the average foot per well?

If you also look at that slide, it gives you the average completed lateral length for each of those producing areas.

I see. Okay. I see it now. Okay. Great. Then as my follow-up, you mentioned about dropping one rig next year due to low gas prices. I think you touched on this with Holly earlier. I just want to make sure I understand it. Just a lot of drilling that you do on your own land and not on land held by production. How do you think about trading off between drilling at current prices and holding off and waiting for higher gas prices?

Well, we're pretty well hedged going into next year – actually, we're in this year. We're at 60% hedged. We've already sold 87% of our gas. And as I said with Holly's question, as we go through the winter season, we'll keep an eye on prices, especially strip prices over the next year or two. And at that point, we'll decide does it make sense to continue with the two rig case or is it time to make a change.

Okay. I see. And then I would like to sneak one more question in. I just want to clarify this. The unit cash cost, the $1.25 per Mcfe, is that the all your all-in cash operating cost at the wellhead?

Yes.

Okay. And then since every company seems to define cost differently the cash cost differently, you mentioned LOE and transportation, does that unit cost include SG&A, financing and taxes?

Yes. It does.

Okay. Great. Thank you.

Thank you.

There are no other questions at this time. I'll turn the call back over to Ken Webster for closing remarks.

Thank you, Marcella. We'd like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 3 p.m. Eastern Time on both our website and by telephone, and will run through the close of business on Friday, November 8th. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com and to access by telephone, call 1800-585-8367 and enter conference ID number 4581569. This concludes our conference call for today. Thank you, and goodbye.