National Fuel Gas Company (NFG) Q3 2019 Earnings Report, Transcript and Summary

Good morning. My name is Suzanne, and I will be your conference operator today. At this time, I would like to welcome everyone to the Q3 2019 National Fuel Gas Company Earnings Conference Call. [Operator Instructions]. Mr. Ken Webster, Director of Investor Relations, you may begin your conference.

Thank you, Suzanne, 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 2019 earnings release and August investor presentation have been posted on our Investor Relations website. We may refer to these materials during today's call. We would like to remind you that today's teleconference will contain forward-looking statements. While National 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 in 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. If you plan on attending, 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, Ken. Good morning, everyone. Before we start with the quarter, I'd like to take a minute to recognize Ron Tanski and his outstanding 40-plus year career with the company. National Fuel has a great team, great assets and a great culture, and Ron very much helped guide us to the path we are on today. He's left a lasting impression on the company, and I wish him the very best in the future. I'd also like to welcome Karen Camiolo into her new role. For those of you that haven't met Karen, she previously held the role of Chief Accounting Officer. I've worked with her since I joined National Fuel, and she is a great fit in her new role. The third quarter was generally a good one for National Fuel. In particular, it was another great example of the benefits of our integrated diversified business model. In the face of lower natural gas prices and lower revenues on our Empire Pipeline system, the continued strength in our utility and gathering businesses helped keep earnings in line with last year and consistent with our internal projections. Operationally, things are very much on track. During the quarter, Seneca brought online two new pads, 1 in the WDA, the other in Lycoming County. The wells were all completed on schedule and contributed to Seneca's 12% sequential growth in production. We continued to optimize our operations, increasing our recoverable resources and driving efficiencies that help us maintain our low cost advantage among our peers. At the same time, our gathering team works closely with Seneca to coordinate the buildout of our system, deploying capital on a just-in-time basis to maximize returns. In California, our activity level continues to increase. Following a multi-month drilling program, we recently commenced steaming operations at our Pioneer development in South Midway. We expect to discuss initial production results on next quarter's call. In addition, we continue to see strong production from our 17N development program. Looking to next year, given the weakness in natural gas prices, we plan to reduce Seneca's drilling activity. Our next rig contract expires this December, and we intend release that rig once it finishes drilling a pad on tract 007 in Tioga County, which we expect will be some time in the second quarter of the fiscal year. While I'm optimistic prices will return to acceptable levels as the supply-demand balance normalizes and as producer activity slows, our reduced activity, which we'll focus on CRV return per Utica wells. We'll preserve our program economics and keep the balance sheet strong. In our regulated transition and distribution businesses, well, we continue to make significant investments to expand and modernize our pipelines. Construction activities are in full swing on our Line N to Monaca project, which is a lateral connecting our system with the new Shell petrochemical facility in Beaver County, Pennsylvania. This expansion, which should be in service right around the end of the fiscal year, will add approximately $5 million in incremental revenues for next year. We continue to see interest in additional capacity in our Line N system both from producers and end users, and I'm optimistic we'll see further expansion of that line in the years to come. Our Empire North project received its notice to proceed from FERC in May. We have since kicked off construction activities at those compressor sites. The long lead items have all been ordered and at this point, everything is on track for an in-service date in the second half of fiscal 2020. As a reminder, this project is fully subscribed and will add more than $25 million in annual revenues. Our FM100 project is also progressing. We filed our certificate application with FERC last month. And on Wednesday, Transco filed its application for the companion Leidy South project. Assuming FERC's normal approval process, we expect our certificate in about 12 months, which will keep the project on track for a late calendar 2021 in-service date. It is a great project for both our pipeline business, which will add $35 million in annual revenues and for Seneca, which will gain a transportation path to the East Coast markets. Earlier this week, Supply Corporation filed a rate case with FERC. That proceeding will address FERC's requirement that pipelines reflect the federal corporate income tax change in their rates. In addition, the filing considers the numerous investments we've made in rate base and the overall increased expenses of our pipeline operations. These rates will go into effect February 1 and subject to refund. The issues in the case are pretty straightforward, so I'm hopeful we can reach a settlement before that. At Utility, our system modernization program is on pace to achieve its replacement mileage targets for the year. For the past several years, we've taken a methodical approach to upgrading our infrastructure to provide the safe and reliable service our customers expect. In our New York jurisdiction, our system modernization tracker provides for timely rate recovery of these investments and provides a modest level of growth in that business. In closing, it was a good quarter for National Fuel, one in which the benefits of integration and diversification were particularly evident. We continue to execute on our plans to grow the company. At the regulated businesses, our modernization and expansion projects are all proceeding according to schedule. On the nonregulated side, keeping the drop in gas prices, scaling back our drilling in Appalachia is the right thing to do, but even at a two rig program, we still expect a solid production and gathering growth in the years to come. Overall, I'm confident that our business model positions us well for future growth and will add value for shareholders. With that, I'll turn the call over to John.

Thanks, Dave, and good morning, everyone. Seneca had a solid quarter with results in line with our expectation. We produced 54.7 net Bcfe during the third quarter, an increase of almost 6 Bcfe or 12% from last quarter. This increase was driven primarily by the addition of 2 pads, a Marcellus pad in the WDA, and a Marcellus pad in Lycoming as well as a full quarter production from 2 pads came online late last quarter. Production guidance for the year remains between 205 to 215 Bcf, around 18% growth year-over-year at the midpoint. Our fourth quarter production will largely be driven by the timing and performance of two new pads, the Utica pad in the WDA, which has just begun the flowback; and the Marcellus pad in Lycoming. For the remainder of the fiscal year, we are in good shape from our pricing perspective with about 40 Bcf or 75% of our expected production at the midpoint locked in physically and financially at a realized price of $2.42. Approximately half of the remaining 13 Bcf is tied to volumes with basis protection and the other half into the spot market. With 26 WDA Utica wells now producing, we continue to be encouraged by our overall results. Once all of these wells have been online for at least 3 months, we will provide an updated type curve and additional insight related to our drill and completion design optimization. And finally, our four new our Utica wells in Tioga County continue to perform at or above expectations. All four wells have now been online for over 4 months. As you can see on Slide 27 in our updated investor presentation, production from these wells has essentially remained flat at an average of 13.8 million per day over this time period. In California, we've produced 575,000 barrels of oil during the third quarter, a slight increase over last quarter. On obtaining our injection permits in both Pioneer and Coalinga, we have recently drilled 23 wells, 16 in Pioneer and 7 in Coalinga. We have also accelerated some facility buildouts at Pioneer as we ramp up our activity level. As a result, we have increased our expected 2019 California capital expenditures by around $5 million to a total of $30 million. As mentioned last quarter, 17N is currently producing over 500 gross barrels per day, and our next phase of development is scheduled early in fiscal 2020. At Pioneer, we have begun steaming the completed wells and expect to see a production response in the coming weeks. At current oil prices and considering our Midway Sunset pricing is currently at a premium to WTI, these projects remain very economic. With the additional activity in California, we have tightened up our fiscal 2019 CapEx guidance to between $475 million and $495 million. Moving to our fiscal '20 guidance. Due to sustained low natural gas prices, we now to plan to drop a rig during the second quarter. As a result of our expected reduced activity levels, our capital expenditures are forecasted to range between $415 million to $455 million, a $50 million decrease from the midpoint of our fiscal '19 guidance range. We plan to bring to production around 15 Marcellus wells and between 25 to 30 Utica wells next year with approximately 2/3 of these wells in the WDA. Our reduced activity is not expected to significantly impact fiscal '20 production growth, but will certainly impact our growth profile beyond 2020. Net production in fiscal '20 is expected to range between 235 to 245 Bcfe, a forecasted increase of around 15% at the midpoint year-over-year. Thereafter, with the 2-rig program, we expect average annual production growth in the mid- to high single digits over the next few years. That said, as you can see on our Slide 29 of our investor presentation, Seneca still expect to be able to generate production that fully utilizes firm sales and transportation commitments. In fiscal '20, we have approximately 87% of our expected gas production locked in physically. Of that amount, almost 92 Bcf or just over 40% is completely locked in with a realized price of $2.40 per Mcf and another 103 Bcf or around 46% is protected from basis risk by a firm transportation, firm sales portfolio. The remaining 29 Bcf or 13% is available for sale into the spot market. And as always, when we see opportunities, we will continue to layer in additional firm sales in an effort to lock in more of this production and avoid price-related curtailments. And with that, I'll turn it over to Karen.

Thank you, John, and good morning, everyone. National Fuel's third quarter GAAP earnings were $0.73 per share. Similar to last quarter, we had a few items impacting comparability related to hedging and effectiveness and the marking-to-market of the investments in the nonqualified benefit plan. Excluding those items, our operating results were $0.71 per share. Last evening's release provides a detailed overview of the larger year-over-year variances, but there are a few items worth discussing. In our E&P operations, despite being well hedged for the year, the recent drop in both natural gas and oil prices had a modest impact on our results for the quarter. We expect that trend will continue for the remainder of the year. We've also accelerated some activities in California to take advantage of the enhanced oil recovery tax credit, which expires at the end of fiscal 2019. This will likely result in Seneca being toward the high end of our $0.85 to $0.90 per Mcfe LOE guidance range for the year. With this in mind, our fiscal 2019 earnings guidance is being revised to a range of $3.40 to $3.50 per share, down $0.10 at the midpoint. Roughly half of this decrease is associated with lower commodity prices, which our guidance now assumes at $2.40 per MMBtu for natural gas and $57.50 per barrel for oil for the remaining 3 months of the fiscal year. The rest of the decrease can be attributed to the acceleration of Seneca's EOR-related activities, a small impairment in our gathering business related to our nonoperated ownership interest in a processing facility and lower margin in our energy marketing segment. All of our other fiscal 2019 guidance assumptions are relatively unchanged and are detailed on Page 8 of last night's earnings release. Looking to fiscal 2020, we are initiating preliminary earnings guidance in the range of $3.25 to $3.55 per share, which, at the midpoint, is a slight decrease from 2019. The biggest year-over-year driver is lower natural gas price realization. We are currently assuming $2.55 per MMBtu for gas prices with spot prices to average $2.20 in the winter and $2 in the summer. In addition to some favorable hedges and fixed price firm sales rolling off during 2019, we also saw some significant favorable spot pricing during the winter months. Looking to fiscal 2020, the forward strip has deteriorated recently. So for reference, a $0.10 change to gas prices, both spot and Henry Hub, impacts earnings by about $0.12 per share. For oil, we are assuming $55 per barrel, and project that our California oil, largely priced off of the Midway Sunset pricing index, will trade at a premium of 108% of NYMEX. As we're all aware, there's been considerable volatility in the forward strip. When we finalize our 2020 guidance in November, we will update to reflect the then current forward strip prices. Another significant year-over-year driver relates to the enhanced oil recovery credit. That credit will not be available in fiscal 2020. This credit has been in place since fiscal 2017 as oil prices remained low. With prices increasing this year, the credit spaces out completely for next year. As a result, we expect that our fiscal 2020 effective tax rate will increase to approximately 25%. These lower price assumptions and tax impacts are expected to be partially offset by higher production. This higher production should help drive total unit cost down with G&A expected to be between $0.25 and $0.30 per Mcfe and Seneca's other unit costs to be in ranges similar to fiscal 2019. Seneca's higher production also has a significant positive impact on our Gathering segment's earnings. We anticipate Gathering revenues to increase to a range of $135 million to $145 million or about 10% from the midpoint of our 2019 guidance. With the modest increase expected in operating expenses, most of this revenue increase should fall straight to the bottom line. Looking at our regulated operations, we are anticipating some modest growth to offset the pricing challenges we are projecting at Seneca. At the utility, we expect margin to increase 1% to 2% over fiscal 2019. This is driven by 2 factors: first, we continue to see a small amount of customer and industrial usage growth supported by an improving economy in our service territories; second, we continue to invest in the safety and reliability of our distribution system, and our modernization tracking mechanism in New York provides timely recovery of these investments. We expect that this margin growth will be offset by modest inflation in our operating costs. Switching to our FERC-regulated pipelines, we expect revenues to increase 2% to 3% to a range of $290 million to $295 million. The 3 main drivers of the increase are: revenues related to the Line N to Monaca expansion project, which is expected to be in service for all of fiscal 2020; revenues associated with our Empire North project, which has a target in-service date in the second half of fiscal 2020; and estimated revenues related to a rate proceeding at Supply Corporation filed earlier in the week. Going in the opposite direction is the full year impact of the loss of the original anchor shipper on the Empire Connector. As previously discussed, 2019 was the cyclically high year of operating costs for our pipeline business. While we expect 2020 O&M expense to be a few percent lower than 2019, we expect an increase in below-the-line retirement benefit costs to largely offset those savings. Altogether, there are a lot of moving pieces between fiscal 2019 and 2020. The diversified nature of our business provides a measure of stability with the predictability and modest growth from our regulated businesses providing a nice offset to the challenging commodity price environment we see. Turning to capital spending. We are tightening our 2019 range to $745 million to $800 million with relatively small to no change in the individual segment ranges. Looking towards 2020, our preliminary CapEx range is $725 million to $820 million. At the midpoint, this is flat compared to 2019. Within the segments, there is some movement year-over-year, with the Pipeline & Storage segment increasing to a range of $180 million to $215 million. This is driven primarily by the ongoing construction of our Empire North project. This increase is offset by lower spending at Seneca based upon reduced activity in the second half of the year. Lastly, from a financing perspective. We expect our capital expenditures to exceed funds from operations by a modest amount in fiscal 2019, resulting from lower commodity prices and a slight change in capital at the midpoint of our range. This will likely leave us with a minor amount of short-term borrowings at the end of September. Looking to next year, with the reduction in Seneca spending, we expect substantially all of our capital expenditures be covered by funds from operations. With that, we will ask the operator to open the line for question.

[Operator Instructions]. And of our first question comes from the line of Holly Stewart with Scotia Howard.

Maybe, John, we could spend just a few minutes talking about the 2020 guide. And then you mentioned in your prepared remarks a kind of mid- to high single digits beyond that. Can you talk about how the activity set has changed? And is that 1 rig in each area?

No, Holly. The rig that we're planning to drop now is in the EDA. With our planned activity in the EDA over the next few months, this will allow us to fulfill our firm sales and firm transportation commitments in both Lycoming and Tioga over the next couple of years. And really in this area, continued activity would generate volumes that would have to be sold in the spot market if we were not able to layer in additional sales. So the two rigs will be in the WDA.

Okay. And does that keep the two crews working then in WDA? Or is there a plan to release one of those crews?

Are you referring to the frac crews?

Yes, sorry.

Yes. Yes. No, obviously, one crew can handle two rigs in the WDA. So we will not be using a spot crew going forward.

Okay. And is that 2-rig program then what is driving the mid- to high kind of longer-term growth numbers?

Yes, it is.

Okay. Okay. Any sense of capital you can give us for that?

Well, going into next year, as we just said, we're going to drop about $50 million. But all in, depending on the completion related to that, it could drop as much as 100 -- a little bit over $100 million.

Okay. That's great. And then maybe for Dave, but you probably provided an update, I guess, last quarter on just kind of where we stood with the Northern Access process. I think since then, the regulators have denied the North East supply enhancement application. Realizing these are very 2 different projects at very different stages, but can you just kind of give us maybe an update on where we are? And kind of where we go from here?

Yes. We're really aren't in a very different spot on that project today versus a quarter go. We, as you know, had had victories in the courts. And with FERC finding waiver on our 401, we're in a position where we could apply for a notice to proceed. But it's pretty clear that New York is going to oppose this project pretty much at any step of the way. So we're thinking that this is really a longer-term project, likely in the 2022, 2023 time frame. And given Seneca's reduced level of activity, delay is not the worst thing in the world.

And your next question comes from the line of Gordon Loy of Raymond James.

So just real quick, I see that 2020 guidance assumes that $2.55 NYMEX gas, which is -- and I guess, could you provide some color on what kind of price would have to see -- dynamics get you to see, I guess, you guys considered adding a third rig?

Yes. Obviously, we'd be looking at the -- the forward strip is going to the driver there. And I'm not sure, we'd look a little bit longer term, so 12, 24 months forward strip. But I would guess $2.65 plus, we would begin to reconsider.

Got it. That makes sense. And then my follow-up is, off of kind of similarly looking at 2020 guide, you have production at 235 to 245 Bcfe for the year. I guess what base decline are you assuming to get to that production guidance?

Could you repeat that question? I didn't understand it.

Yes. So I just wanted to get an idea of kind of what is the base decline that you're assuming when you're looking at the 2020 production guidance?

Yes. It varies across our area. But our Marcellus is typically 18%, 20% base decline. Our Utica is a little bit higher because it's a -- we've been drilling much -- many more new wells. That's probably, I would say, 25% to 30% base decline.

Our next question comes from line of Ryan Levine of from Citi.

Regarding your dropping in the rig or potential dropping in the rig next year, can you speak to the Midstream implications of that?

Well, the guidance that we put out from a capital standpoint reflects the reduced level of activity. As I said in my remarks, we're going to focus on the return trip projects, drilling Utica wells pads that had previously been developed for the Marcellus. So that should keep our relative level of gathering spending pretty low.

Okay. And then in terms of your basis exposure next year, is it still about 1/3 between the three different gas basis that you exposed? Or this is the change in drilling plan alter your exposure to different gas basis?

Yes. Really most of the exposure is going to be on the spot market. And with the increased activity, it'll probably be increasing within the WDA since we'll have continue to run 2 rigs there. And 313 historically has run from anywhere from $0.10 to $0.30 higher than what we've seen in the TGP 4 and Leidy receipt points. But that's where we'll begin to see increased spot exposure is really in the WDA.

Okay. So 3-1-3.

[Operator Instructions]. Our next question comes from the line of Chris Sighinolfi of Jefferies.

John, I wanted to touch on, I guess, first on a few Seneca items. You had detailed in the prepared remarks, I think if I heard you correctly, 15 Marcellus and 25 to 30 Utica wells next year. But I'm curious the cadence of pad completion in the production growth throughout the year. Is there anything you can share at this point that would help us sort of better refine the shape of the production curve for the year?

Yes. 2/3 of those wells will be in the WDA. And I'd have to sit down and calculate out the cadence per quarter. I have not done that. So that's something we'll have to back up and get for you.

Okay. I mean at this point, are you thinking that there is going to be a meaningful growth in back half versus front half? Or I guess anything generically you could say at this point as you think about the year in total?

Yes. First few pads come on towards the end of the first quarter, early in the second quarter and then, its' fairly consistent for the remainder of the year.

Fairly consistent adds?

Yes. Yes.

Okay. And I guess as we think about fiscal '20, with that plan with running 2 drilling rigs but 1 completion crew, is the -- and I guess that the forecast you're giving beyond that of being mid- to high single digits, is the uncompleted but drilled inventory at the end of next year going to shape up to be fairly similar to this year? Or are you adding DUC inventory with that change?

No. We'll actually -- we'll have a spot crew at least going through the second quarter of 2020 and then it'll disappear. And at that point, we will begin to eat into our DUC count.

Okay. Okay. And if I can keep going, following up on Holly's question about growth beyond 2020. I just wanted to verify, so that outlook's predicated on the reduced profile two drilling rigs, one completion crew?

Yes. Right now, we're forecasting two rigs and a single crew going forward beyond 2020.

And I guess as I look at the entire crew, there's been a pretty meaningful pullback of activity on all the regional E&Ps. So I mean are there -- I don't know how long you have these teams contracted, but other opportunities to push service cost lower just given the aggregate reduction in regional activity?

Yes. As we move into the winter months, Chris, we'll certainly be looking to continue to try to layer in additional sales. But once we drop that first rig and we see where pricing is, then we'll certainly take a step back and reassess what or activity looks like going forward.

Okay. And then I have two more, if I could. Just Slide 9. John, you would be telling that this is the latest presentation, the projected Utica gathering CapEx per well, just noticed that without any change the footnotes or anything, it's steadily risen over the last couple of quarters. I think the point of the slide is still hold what you intend, which is that it's very efficient to use the same pads that you have in the Marcellus program that Dave mentioned earlier. But just curious about what that cost creep has been driven by?

Yes. Chris, this Dave. We had some questions on this last night, and took a -- took another look at this number and it turns out we had a bit of bust in it. The number should really be closer to $430. We're going to further scrub the numbers and get an updated deck out next week.

Okay. So $430, I guess, that would be fairly consistent with last quarter's spend.

Yes.

Okay. And then my final question, Karen, first, I guess, congrats on the promotion and best of luck in your new role, I didn't want to let the opportunity to asking you a question.

Oh, well, I'll check back and Dave didn't have to answer any questions for at least 3 teleconference. So let's go for it.

I'm not sure if you've had a chance yet to meet with the agencies or if Dave had this conversation with them the last time he was in front of them. But I'm just wondering as we think about lower gas prices, their impact on cash flows from unhedged production and your investment plans across the businesses. Where does the debt-to-EBITDA leverage limit exist for you under your current credit ratings?

3.5x EBITDA.

3.5? Okay, great.

Yes.

Yes. That would be with Moody's. S&P would generally look more towards FFO to that being in kind of the 30% range. And we'll look at our forecast -- even at these lower prices, we don't really push up on either of these limits.

And I don't have any further questioners in the queue at this time. I'll turn the call back over to the presenters for the closing remarks.

Thank you, Suzanne. 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, August 9. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com, and to access by telephone, call 1-833-287-0795 and enter a conference ID #2194110. This concludes our conference call for today. Thank you, and goodbye.

Thank you very much. This does conclude today's conference call. You may now disconnect.