National Fuel Gas Company (NFG) Q1 2019 Earnings Report, Transcript and Summary

Good morning. My name is Adam, and I will be your conference operator today. At this time, I would like to welcome everyone to the Q1 2019 National Fuel Gas Company Earnings Conference Call. All lines have been placed on mute to prevent any background noise. And after the speaker’s remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. Ken Webster, Director of Investor Relations, you may begin your conference.

Thank you, Adam, 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 Ron Tanski, President and Chief Executive Officer; Dave Bauer, 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 first quarter fiscal 2019 earnings release and January 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. National Fuel will be participating in the Scotia Howard Weil Energy Conference in March. 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 Ron Tanski.

Thanks, Ken. Good morning, everyone. Thanks for joining us. Just a quick word on logistics today to avoid travel complications due to weather in the Midwest and Northeast, I asked John McGinnis to stay safely in Houston and call in from the office there. And now on to our earnings release, where you can see that we had a really good opening quarter for our 2019 fiscal year. Our operating plans that I laid out during our call last November are moving along right on target. Our steady approach and our upstream drilling business is working out quite well. We continue to fill the firm transportation capacity that we have lined up, and we don't have to drill an excessive number of wells to hold expiring leases. Early results in our Utica development show that production is right in line with our initial projections and that has helped us to increase our overall production level with just the three rigs that we have active. In our Gathering operations, which were on pretty much in lockstep with Seneca, our capital expenditures will be lower this year since we're revisiting existing Marcellus pads to drill deeper Utica wells and only minor additions to the Gathering infrastructure are necessary to take in production from the newer Utica wells. In our interstate pipeline business, there have been no major changes to the status of our pipeline projects. We're almost ready to kick off construction of our Line N to Monaca lateral that will be used to provide operational gas to the Shell petrochemical plant being built in Beaver County, Pennsylvania. With respect to our other expansion projects, our engineers are busy working on the details of our Empire North project, which still has a target in-service date for the second half of fiscal 2020. We're expecting to receive our FERC certificate for this project within the next two months. Our engineers are also busy with our FM100 project that's paired with Transco's Leidy South project, both of which have a late calendar 2021 target in-service date. And it's our lawyers rather than our engineers that continue to focus on our Northern Access project. We are encouraged by our recent Federal DC Circuit Court decision in an unrelated California and Oregon case that determined that state agencies cannot exceed one year in their processing of a Section 401 Water Quality Certificate. We are hoping that this recent federal court decision will allow the FERC to quickly dismiss New York's rehearing request on FERC's most recent authorization for our project. In our Utility business, our system is holding up quite well as we've reached peak flow of one billion cubic feet or more per day during the bitter cold over the last four days. But for the financial quarter, we were only about 3% colder than normal in New York and just about normal in Pennsylvania. I'd like to give a shout-out to all of our field operations' folks and the people manning our phone centers for keeping the gas flowing and fueling our customers' furnaces and boilers on the coldest of winter days like, we've experienced over the past week. For us, it's not a surprise that our system has held up so well. Over the last nine years, we've invested almost $700 million to upgrade our utility system and keep it reliable for our 750,000 customers. We've been able to do that and keep our residential customer rates at levels that are at the lowest of any utility in both New York and Pennsylvania. What is surprising to me anyway is that given New York state's proximity to one of the most prolific and inexpensive clean-burning fuel sources in the world, Albany recently announced a target of 70% renewable electricity generation by 2030 in a Green New Deal to ultimately make New York carbon-neutral. That's a pretty tall order given that right now approximately 40% of the electricity that's generated in the state is generated with natural gas, and in our service territory, over 95% of households, heat with natural gas. So far, the transition away from natural gas isn't going so well in New York City where Consolidated Edison recently announced a moratorium on hooking up new gas customers. People looking to switch from fuel oil and developers looking to build new buildings in New York City are outraged that they can't enjoy the economic and environmental benefits of natural gas. We believe that natural gas can continue to provide solutions as we continue to transition to renewables, but that transition could take a long time. In National Fuel service territory, our system can adequately handle our customers' needs without a problem, but I'm not sure what might happen if state policies are fully enacted that will require our customers to change out their heating systems and move away from natural gas as a fuel that they've relied on forever. While people like to talk about switching to renewables, no one ever continues the discussion long enough to talk about the costs to the ultimate consumer involved in such a switch. We'll be keeping an eye out and get involved in state energy policy discussions and try to assure that our customers can maintain access to reliable and affordable energy solutions. So what do I see for the overall company for the rest of the year, well we'll be sticking with our same basic plan, operating three drilling rigs to develop our acreage and grow production at a steady pace. And we'll continue to work on our pipeline projects in our interstate pipeline business. We will have a slight outspend this year that's easily handled with the cash on our balance sheet. It's our intention to generally live within cash flows, but we don't expect to be in the capital markets until we refinance one of our long-term notes that matures in 2022. I think our shareholders can take comfort in the consistency of our operating plans and our commitment to returning capital to shareholders through our dividend payments that we've increased each year for the last 48 years. I'll ask John McGinnis to give us some more details on Seneca's operations.

Thanks, Ron, and good morning from Houston everyone. Seneca had a great first quarter. We produced 49.2 Bcfe compared to 40.1 Bcfe in last year's first quarter, an increase of almost 10 Bcfe or 23%. In Pennsylvania, we produced 45.3 Bcfe, up by 28% compared to last year's Q1. On a sequential basis, quarterly production increased by around 2 Bcfe or around 4%. As a result of maintaining a steady three-rig pace in Pennsylvania, we should continue to see quarter-over-quarter production growth through the remainder of the year. We have marketing curtailment early in the quarter, just over 0.2 Bcf related primarily to delays in the Atlantic Sunrise in-service date. But spot prices quickly rebounded and have been strong since ranging in the plus/minus $3 neighborhood. Our fiscal 2019 CapEx and production guidance remain the same with capital expenditures ranging from $460 million to $495 million and production ranging between 210 to 230 Bcfe. And please recall this assumes no significant marketing curtailment for the remainder of the year. During the quarter, we brought online seven new Utica wells in the WDA, three at the end of November, and another four at the last week of December. The completed lateral length related to these wells average well over 9,000 feet, so they are taking a bit longer to clean up, but very early results suggest that these seven wells are all in line with our WDA Utica type curve expectations. We now have 17 Utica wells online in the WDA with an additional 10 Utica wells remaining later during the year. Our type curve remains at 1.7 Bcf per thousand foot and this curve can be compared to our 17 well average in our most recent investor presentation on page 18. Once all 27 wells have been online for a few months, we will then provide an updated type curve and provide additional insight related to our drilling completion design optimization. As a reminder, our testing to date has been focused on drill targets, stage spacing and well spacing during this early phase of appraisal. Once optimized we'll begin focusing on profit loading and profit, type and mix among other factors. We have many years of Utica development inventory on our WDA fee acreage so we'll then be deliberate and patient in our approach towards optimizing well and completion design as we move forward. Our next WDA Utica appraisal well is currently scheduled for late fiscal 2019 located about five to 10 miles northeast of Boone Mountain. For the remainder of the year, we plan to bring to production 10 Utica and six Marcellus wells in the WDA, and four Utica and 13 Marcellus wells in the EDA. But please keep in mind, our development plans are subject to change during the year. Our current development pace will allow us to grow naturally into our firm transportation commitment at each of our key receipt points over the next three years. This includes, our Atlantic Sunrise volume commitment of 190 million a day in Lycoming, our firm transport and sales portfolio of around 125 million a day in Tioga, which includes our Tract 007 Utica development and our most recent 330 million a day Leidy South commitment, which allows us to continue to develop our significant Marcellus and Utica WDA inventory over the next decade and provide access to a market that is currently trading well above NYMEX. We expect natural gas production to range between 194 and 214 Bcf this fiscal year, an increase of over 25% from fiscal 2018 at the midpoint. As stated prior, we produced 45.3 Bcf in the first quarter and during the second quarter we plan on bringing online six new wells, two Marcellus wells in Lycoming, and four Utica wells on our 007 Tract in Tioga. These wells will be the first wells brought online in Tioga since late 2016. Moving forward, we've locked in approximately 114 Bcf of firm sales in Pennsylvania at an average realized price of $2.41 per Mcf and another 29 Bcf of production with basis protection through our firm sales portfolio. Therefore, we already have over 85% of our remaining fiscal 2019 production protected by firm sales securing significant growth at attractive prices. We currently estimate around 16 Bcf available for sale into the spot market, but as we see opportunities we will continue to layer in additional firm sales in an effort to avoid potential price-related curtailments. In California, we produced 654,000 BOEs of oil during the first quarter, a decrease of around 17% from last year's first quarter. This decrease was largely driven by the sale of our Sespe oilfield and due to a natural decline across our fields. And to a lesser extent, a temporary drop in steaming activity at South Midway Sunset also contributed to both a small drop in oil production and LOE. Dave will add a bit more detail regarding California operating expenses in a moment. Finally, we have recently received our requested steam injection permit for our Pioneer farm-in located adjacent to our South Midway field. As a result, we will begin drilling both production and steam injection wells in Pioneer this year. We should begin to see production growth related to this field during fiscal 2020 as our steaming operations begin to heat the reservoir. In addition at Coalinga, we have recently drilled a successful saltwater disposal well that increases our available water disposal volume. As a result, this will also allow for new production wells to be drilled this year, and it will be our first development activity in Coalinga since 2015. We continue to generate significant free cash flow in California and around 79% of our expected fiscal 2019 oil production is hedged, at an average price of $57.57 per barrel. And with that, I'll turn it over to Dave.

Thanks, John. Good morning, everyone. Overall, the first quarter was a good one for National Fuel, with each of our major operating segments delivering increased earnings over the last year. Consolidated GAAP net income was $1.18 per share. Adjusting for items impacting comparability, operating results for the first quarter were $1.12 per share, up 10% compared to last year's first quarter. To echo Ron's earlier comments, our focus in 2019 is on execution. With line upside on future pipeline capacity out of the basin, our plan has us growing the upstream and midstream portions of our business, while living within cash flows over the medium and long-term. First quarter was right on track with that plan. Production and capital met expectations and we had a nice tailwind from natural gas prices. Our first quarter results had a fair amount of accounting noise related to tax reform, hedging ineffectiveness, and changes in accounting standards. First, as you may recall, tax reform made AMT credits refundable subject to sequestration. Past fiscal year when we recorded a receivable for those AMT credits, we booked a $5 million reserve for that sequestration. This past December, the Office of Management and Budget determined that sequestration would not apply to AMT refunds, so we reversed the reserve in this quarter's results. The second item impacting comparability relates to a $6.5 million unrealized gain from ineffectiveness associated with hedges of our California oil production. The financial hedging market at Midway Sunset is fairly a liquid, so instead we used a combination of WTI and Brent contracts to hedge that production. Over the past few quarters, the spread between Midway Sunset and WTI pricing has tightened considerably, so much so that we've experienced ineffectiveness on a portion of our WTI hedges. In other words, the value of our hedging contracts has increased far more than our underlying production is decreased which is a good thing. Under the accounting rules, this ineffectiveness was recorded as a gain in the quarter's results. We were required to adopt two new accounting standards this quarter. The first relates to the investments we've made in marketable securities to fund our non-qualified benefit obligations. Previously, changes in the fair value of those investments flowed through other comprehensive income, but effective October 1st, we now have to mark those investments to market through the income statement. With the decline in the equity markets in December, we recorded approximately $6 million in losses on these investments which we highlighted as an item impacting comparability. Going forward, we intend to adjust our operating results for this mark-to-market activity to the extent its material for a given quarter. We also adopted new pension accounting rules that require us to remove approximately $7.4 million of non-service pension costs from our O&M expense and present them below operating income, in our case, in the other income and deductionable line item on the income statement. Though this change gives the appearance of higher operating income, particularly at the utility, it has no impact on earnings. We re-classed last year's income statement to reflect these new rules, so the amounts in last night's release are apples-to-apples with this year. Page 64 of our current IR slide deck contains further details on this change. Excluding these accounting items, our results for the quarter were right in line with our expectations. The earnings release does a good job highlighting the key drivers of quarter-over-quarter earnings, but there were a few items worth noting. At Seneca, NYMEX and spot prices increased meaningfully in the latter half of the quarter. We were very well hedged to start the year, so we didn't see a large benefit, but it was nonetheless a nice uplift to our in-basin spot sales and unhedged NYMEX firm sales. On the flip side, the end of year run-up in NYMEX did cause an increase in the Pennsylvania impact fee which was reflected in Seneca's other taxes line item. That fee is determined based upon the age of our wells and the average net NYMEX gas price for the year. The run-up in the December contract pushed the calendar 2018 average price up over $3 per MMBtu, which moved the impact fee into a higher tier for the entire year. We have been accruing at the lower tier for the first three quarters of calendar 2018, so we had to catch up that accrual. As a result, other taxes increased by $2.1 million. Based on the natural gas prices and our guidance $3.25 for winter and $2.75 for summer, we expect calendar 2019 prices will average a shade below $3. Therefore, we will be accruing for the impact fee at the lower tier for the remainder of the year, or until our pricing expectations change. In California, production was down year-over-year, principally due to the sale of our Sespe field last spring. We also saw a slight decline in California production related to a short-term reduction of our steaming operations at Midway Sunset, though we are now back to normal injection rates and production is returning to its natural decline. This phenomenon which was the primary driver of the drop in per unit LOE in the first quarter occurred when SoCal natural gas prices spiked late last summer. Looking forward, we anticipate the second quarter – being a higher LOE quarter likely in the $0.90 to $0.95 range, due to the combination of high steam fuel prices and a return to normal steam injection rates. However, on a positive note, we made some changes to our supply portfolio and outsourced most all of our steam fuel and indices that are more closely tied to Rockies basin. This should result in Q3 and Q4 steam costs returning to more normal levels. Therefore, we're keeping our full year LOE guidance at $0.85 to $0.90 per Mcfe. On the regulated side of the business, the quarter was right in line with our expectations. That being said, there was a fair amount of activity with the FERC. In December, Supply Corporation filed its Form 501-G. In it, we committed to file a new Section 4 Rate Case by the end of this coming July. If you recall, our 2015 rate settlement requires us to file a rate case by the end of calendar 2019. Now – assuming we now file in July, new rates will go into effect in February 2020. At Empire Pipeline, we reached a settlement in the rate case we filed in June. As we discussed on prior calls, the case was filed because of the loss of a large shipper that had Canadian import capacity on the original Empire Connector project. The settlement also addresses the impact of tax reform on our rates. The outcome was in line with our expectations with an estimated increase to Empire's revenue of $4.6 million annually. The settlement removes one of the larger uncertainties in our Pipeline & Storage revenue forecast, and therefore allows us to reaffirm our revenue guidance for the segment of approximately $285 million for the full fiscal year. Turning to guidance, we're increasing our earnings expectations for the fiscal year to a range of $3.45 to $3.65 per share at the midpoint of $0.05 per share increase over our previous guidance. This increase reflects our strong performance for the first quarter and our updated commodity price assumptions detailed in last night's release. Our capital spending plans are unchanged. We continue to expect that our funds from operations could cover substantially all of our capital spending for fiscal 2019. We might be in a short-term borrowing position at low points in our working capital cycle, but over the course of the year, any financing needs should be met from the cash balance with which we started the fiscal year. With that, I'd like to turn it over to the operator to open the line for questions.

[Operator Instructions] And your first question does come from Holly Stewart of Scotiabank Weil. Holly, your line is open.

Good morning gentlemen. Maybe the first one for John. John I think you kind of talked about the new EDA production coming on in 2Q, 2019 but you went pretty fast. Can you give us those well numbers again?

Sure. Good morning Holly. We have two wells in this quarter, fiscal two quarter. We have two wells that will come on in Lycoming, Marcellus wells, and four wells that will come on in Tioga and there'll be four Utica wells.

And that's all in 2Q?

And that's all in Q2.

Okay great. And then maybe as it relates to that are you full on your Atlantic Sunrise capacity today?

Yes.

Okay, great. Thank you. And then maybe one for Dave or John just thinking about basis here going forward, I think the basis for the quarter was a little weaker than our expectations. So don't know if that's firm sales running through there or if that's just the addition of the Atlantic Sunrise capacity. Could you just help us think about that going forward?

I mean it was certainly stronger than we expected during the early winter months and -- but it has fallen back. And I think it's just that production is so high in Pennsylvania these days; and with the bearish storage report, I just think we've seen a bit of a falloff related to basis in that area. It's hard for me to really predict how it's going to look going forward to tell you the truth.

Okay. All right great. Thanks guys. That’s all I had.

Your next question comes from Chris Sighinolfi from Jefferies. Chris, your line is open.

Yes. Thanks a lot. Following from Holly's questions, maybe just to start on firm sales, it looks like we added a bunch in the period at least since the December deck or the back half of this year and early fiscal 2019. So John I'm just curious is that something that you had stated as an ambition to fill that wedge over time? And we are obviously paying attention to the dialing back in ambitions from some of your gas E&P peers in the Northeast. Just wondering how that market is shaping up for you? Is that sort of consistent with prior expectations or have you done arguably more to date than you thought you would at this point?

I think it was consistent. Definitely the increase in prices as we moved into November helped a little bit. But as they did run up in mid-November, we added a portfolio of firm sales both a combination of fixed basis and also fixed price, and really our focus was the back half of fiscal 2019 going into 2020. Our 2019 is in great shape as I stated before, we're about 85% hedged-plus, and so we're fine there. We'll continue to focus on fiscal '20. But I think it was in line with what we're thinking our expectations. I think we added if I remember correctly, is about 50 a day this summer in the fiscal 2019.

Yes that looks like the delta from -- at least from the presentation slides, so okay. That's helpful. And then I guess switching gears a little bit, Dave I appreciate the color on the Empire settlement. I realized it's not fully signed and sealed by the FERC yet, but you've mentioned that in line just to confirm the expansion project that you have there that's entirely negotiated, is that right? And it's not impactful at all any outcome change?

The Empire North project?

Yeah.

Yeah, yeah, that's an un-negotiated rate deal.

Okay. And then Dave, I saw on in – this is just a point of clarification or curiosity from my perspective, I saw about $8 million in what you say is net share repurchase in the quarter. Is that just to satisfy year-end equity grants?

I believe so. Yes, I believe that's the case. We'll double check that, and if it's not, Ken will get back to you.

Okay. It just was something that stood out and I haven't seen that number in a little bit. So just figured I would ask about it. And then maybe the final question. The issues from ConAd in Westchester County, you mentioned sort of the costing items that wanted to have a renewable portfolio. Can't help but notice if that's part of what they're discussing in California that pertains to problematic PPA agreements that PCG has that maybe started some of their financial issues. Obviously, the issues had gotten worse with the fires, but other than identifying has there been any tangible discussions with the commission about either what New York or Pennsylvania does in regard to approaching this?

No, I think that's the struggle, Chris is there's all these pronouncements, but when it comes time to actually getting renewable plant on the ground, frankly those developers are having as much trouble citing their new -- either wind turbines or solar farms as much as we are getting pipelines on the ground. There seems to be -- no matter where someone wants to put something up, there's somebody going to be complaining about it or they don't want it in their backyard. So I think it is going to be a struggle to just to get those sources developed, but what would be nice is they'd be able to have a discussion about it rather than like things these days so much being very polarized and just instead of shouting matches, we just need to talk and have everyone understand what those costs are going to be.

Okay. That’s great. Thanks a lot for the color. Bye guys, appreciate it.

[Operator Instructions] And we do have Chris Sighinolfi back from Jefferies. Chris, your line is open again.

Hey, thanks, guys. I was going to get back in the queue, but I'm the only one there. Dave, one question, follow-up question I did have, you were discussing impact fee tiers. I am less versed -- well-versed in sort of where those different tier points hit you. Can you just describe that a little bit or revisit in a little bit more detail?

Yeah, I am pretty sure Chris that it's -- the $3 is a line in the sand. For us, this past year, it was -- $3 was the tier. John, honestly I don't remember how the tiers move from that. John, do you know?

Yeah, actually I do. Actually the ranges above $3 in year one it's about $50,000; below $3 it drops $5,000. So it is a range that goes from $2.26 to $2.99 that for each well both producing and drilled it will drop that impact fee by $5,000. So it adds up again we have quite a few wells.

Yeah, sure and that's the realized price on average in the first year at that point?

Yes, that's the annual average not the realized price. It's the average Henry Hub NYMEX across that calendar year.

Okay, wonderful. Thanks a lot guys. I appreciate the added color.

And we have no further questions at this time. So I'll turn the call back over to Ken Webster for some closing remarks.

Thank you, Adam. 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 3:00 P.M. Eastern Time on both our website and by telephone and will run through the close of business on Friday, February 8th. To access to replay online, please visit our Investor Relations' website at investor.nationalfuelgas.com and to access by telephone call 1800-585-8367 and enter a conference ID number 7996513. This concludes our conference call for today. Thank you and goodbye.

And thank you for your participation. You may now disconnect.