National Fuel Gas Co (NFG) 2018 Q1 法說會逐字稿

Good morning. My name is Mike, and I will be your conference operator today. At this time, I would like to welcome everyone to the Q1 2018 National Fuel Gas Company Earnings Conference Call. (Operator Instructions)

I will now turn the call over to Brian Welsch, Director of Investor Relations. You may begin your conference.

Thank you, Mike, 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 Corporation. At the end of the prepared remarks, we will open the discussion to questions.

The first quarter fiscal 2018 earnings release and February 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.

And with that, I'll turn that over to Ron Tanski.

Thanks, Brian, and good morning, everyone. We started off our 2018 fiscal year with a very good first quarter, and Dave Bauer will review the numbers and all the changes brought about by the new tax law in a little bit.

Our field operations are moving along all according to plan, and there was no real excitement during the quarter, which is a really good thing in the natural gas business, where surprises are generally not a good thing.

The one item that is not following along our original plan is our Northern Access pipeline. As you know, we are waiting for either a decision from the Second Circuit Court of Appeals, overturning the denial of a Water Quality Certification by the New York DEC or a decision on a request for rehearing on our FERC certificate, or FERC could determine that the New York DEC took too long to act on our application for the Water Quality Certification. While there are no set timelines for either of these proceedings, we estimate that we might hear from the Second Circuit in the summer. We could hear from the FERC at any time.

While we wait to see the outcome of our Northern Access proceedings, we continue to look at ways to build or acquire more transmission capacity out of our Western Development Area. A project of any size usually has a long lead time, and we're finding that to be true in this case also. As I said, on previous calls, we're looking at possible options, both on a standalone basis and with partners, but we're not far enough along to provide any details today.

In the meantime, Seneca continues to manage its drilling program to focus on drilling and completing wells where we have adequate takeaway capacity or the ability to lock in firm sales.

Our 2 active drilling rigs are splitting time between the Eastern Development Area and our Western Development Area. The drilling in the EDA is focusing on wells that will be available to fill our new capacity on the Atlantic Sunrise pipeline that is projected to be up and running in July.

In our WDA, we're finding opportunities to lock in additional sales at acceptable prices for delivery into the Tennessee 300 line. We have flexibility to move rigs between these 2 areas depending on our ability to lock in sales.

As we note in our earnings release, we still have a robust capital expenditure program this year. While it's not as aggressive as the President's $1.5 trillion infrastructure spending program, we continue to invest in modernizing our pipeline systems. Older pipelines continue to be renewed or replaced at our transmission system that usually provides future opportunities to increase throughput. On our utility distribution system, we've reduced the already low occurrence of small leaks to their lowest level in years.

We've got some tracking mechanisms that allow us to incorporate a portion of these investments into our rates on a limited basis without the need for filing a rate case, but we're also mindful of trying to live within cash flow where we can. One of our larger transmission projects on the drawing board is our Empire North Project that we've talked about previously. We're putting the final touches on our FERC application and should have it filed this month. As a reminder, this is a project designed to add 205,000 dekatherm per day of throughput at our Empire Pipeline through the addition of compression.

Our target in-service date for the project is the first quarter of fiscal 2020. For the next few quarters, we're taking care of business, keeping our existing pipelines full and safe, and keeping our Utility customers safe and warm.

I'll turn the call over to John McGinnis to give an update on our Exploration and Production operations.

Thanks, Ron, and good morning, everyone. Seneca produced 40.1 Bcfe during the first quarter compared to 44.9 Bcfe in last year's first quarter. If you recall, last year's first quarter gas production in Pennsylvania was much higher than anticipated due to flush production from wells that have been curtailed, in some cases, for over a year. In Pennsylvania, production from our fiscal '17 fourth quarter to first quarter '18 was essentially flat, just slightly lower by 0.2 Bcf.

We had voluntary price curtailments in October and early November that totaled around 1.2 Bcf net and some unexpected operational curtailments that I'll touch on a bit later. There have been no additional marketing curtailment since early November with the arrival of cold weather, in-basin spot pricing is really improved, averaging around $3 per MMBtu in January across our receipt points.

With respect to our operations. We have recently brought on a new pad in Lycoming County. This is the first pad developed with the second rig added in May last year. First production from this pad occurred in early January, and current production is over 80 million a day from 6 wells. We will continue to be active drilling in Lycoming County for at least another 3 to 4 months as we build docks ahead of the projected July 2018 in-service date of Atlantic Sunrise.

And moving to the WDA. We remain at 8 Utica wells drilled and completed. The most recent 3 Utica wells are located on a pad, where we are currently completing 12 Marcellus wells, our final pad in the joint development agreement with IOG. During the completion operations on this pad, we have shut in these 3 Utica wells. As such, we plan to provide a more detailed update on Utica well performance next quarter.

We have drilled 2 more Utica wells in the CRV area. These will be completed over the next month, and should be online during our third quarter.

Finally, as we continue to transition towards a full Utica development program, we have 10 more Utica wells scheduled to be drilled in the CRV area during the remainder of the year. Four of these wells will be drilled on the Rich Valley area, immediately adjacent to our strongest Utica well to date. This well has an EUR per 1,000 foot over 2 Bcf, and has produced over 1.5 Bcf over the first 8 months. All of these new Utica wells should be brought online in the first half of fiscal '19.

In California, we produced 671,000 barrels of oil during the first quarter, a slight decrease of less than 3,000 barrels from the fourth quarter. The small decrease in production was primarily due to the fact that we elected to shut in our Sespe oil field for 17 days to ensure the safety of both our employees and the field, while the Thomas wildfire swept through Ventura County. The Sespe field is now back on production, and we are fortunate the fire never reached our field, so no damage was caused.

Our production at both North and South Midway Sunset continued to grow quarter-over-quarter, and we expect that trend will continue through the remainder of the year.

As expected, with the increase in both oil and gas prices, as industry begins to ramp up their activity level, we have seen a corresponding increase to service costs. Though we continue to remain one of the lowest cost operators in Pennsylvania, service costs have been -- have increased between 10% and 15% this past quarter, and are now up just over 20% from a year ago. The impact of higher costs on our well economics is noted on Slide 20 in our Investor Relations deck. That being said, our team continues to do a great job on improving operational efficiencies, and we're confident we can offset some of these service cost increases. However, we are increasing our capital expenditures forecast by $15 million or 5%, revising our guidance to now range between $300 million and $330 million. California will range between $20 million to $30 million, and Pennsylvania will increase to between $280 million to $300 million.

We are also lowering our fiscal 2018 net production forecast by 5 Bcfe to now range between 180 Bcfe to 195 Bcfe. This is primarily driven by marketing and operational curtailments during the first quarter and minor adjustments to the timing of our Lycoming County development plan towards the end of the fiscal year.

As I mentioned earlier, we voluntarily curtailed 1.2 Bcf net due to low spot prices. And in addition, we have a couple of Bcf of unexpected operational curtailments. A significant portion of the operational curtailments were related to a delay in bringing on 2 new compressors at our Covington Field and Tioga County. The compressors were delayed almost 2 months, both coming on -- with both coming online towards the end of December. The Covington field, however, has responded well, and is now performing better than projected.

We also had a number of Marcellus wells temporarily go offline in the WDA due to the completion of a nearby centrally located pad. Most of these wells have since been brought back to production.

So finally, for the remainder of the year, we have around 83 Bcf or 62% of our gas production locked in physically and financially at a realized price of $2.50 per Mcf. In addition, we have another 32 Bcf of gas physically sold with bases locked in, leaving only a small portion of our forecasted production exposed to in-basin spot pricing for the remainder of the year.

And with that, I'll turn it over to Dave.

Thank you, John, and good morning, everyone. For the first quarter, National Fuel reported earnings per share of $2.30. U.S. federal tax reform led to some large adjustments in the quarter, but beyond that, the quarter was fairly straightforward. Stripping out the $1.29 per share adjustment to our deferred tax balances, earnings were $1.02 per share compared to $1.04 last year. Our regulated operations performed in line with expectations and were generally consistent with the prior year.

In the E&P segment, the sustained increase we've seen in crude oil prices was more than offset by lower production and lower realized natural gas prices due to the exploration of some favorable hedges.

Primary driver of our results for the quarter related to federal tax reform. As you know, the federal statutory rate decreased from 35% to 21% effective January 1 of this year. National Fuel tax year, like our fiscal year, runs from October 1 to September 30. IRS rules are pretty specific on how we deal with this midyear rule change. For fiscal '18, they require us to use a blended federal rate of 24.5%, retroactive to October 1, 2017. Then, in fiscal '19, our rate will drop to 21%.

The drop in the tax rate will have a meaningful impact on our future earnings. As you saw in our release, the move to a 24.5% federal rate increased earnings by $0.11 per share during the first quarter. Looking to the full fiscal year, we anticipate our effective tax rate will be approximately 27%.

We expect a further drop in our effective rate in 2019 once we've transitioned to the new 21% rate. We're still awaiting details on certain aspects of tax reform such as potential limitations on the deductibility of interest expense and executive compensation. But for now, we're assuming a long-term consolidated effective tax rate in the 25% area.

In our Utility segment, we established a refund provision to defer the impact of tax reform. While there is some regulatory uncertainty associated with this adjustment, we believe it is a reasonable course of action based on prior state regulatory treatment.

The New York Commission has already instituted a proceeding to study the Tax Act's impact on the states utilities, and that the commission has clearly stated its intent to preserve the net benefits of the Tax Act for ratepayers, either through deferral accounting or otherwise.

The Pennsylvania Commission has assigned the item for review, but to date, there has not been any specific action.

The pipeline segment did not record a refund provision because supply in Empire's rates have been set in FERC-approved negotiated black box settlements, which do not identify individual revenue components. FERC has encouraged rate settlements to resolve cases and has generally been reluctant to revise them. To-date, FERC is not open to general proceeding to review this matter. We'll continue to monitor and make any adjustments that may be necessary in the future.

Tax reform also required us to remeasure our deferred income tax assets and liabilities on the balance sheet using the new statutory rate. Like a typical energy company, we have a significant net deferred tax liability due to the accelerated depreciation of fixed assets and intangible drilling costs. As a result of the remeasurement, our net deferred tax liability was reduced by $448 million. The bulk of that adjustment, roughly $337 million related to our rate-regulated businesses and was deferred as a regulatory liability on the balance sheet, while we worked through the rate-making treatment with our regulators.

The remaining $111 million related to our nonregulated operations, and that flowed through the income statement, resulting in the $1.29 per share in earnings that I mentioned earlier.

Pipeline and storage business had a good quarter. As expected, revenues were basically flat compared to prior year, but O&M expense moved in the right direction, down $3 million from last year.

Looking to next year, we do face a bit of a challenge in that business. As you recall, the Empire pipeline has volumes contracted in both directions on the connector portion of its system. The South to North path is clearly the more valuable of the 2 pads. The full amount of that capacity has been sold under long-term agreements, and we plan to further expand this pad with the Empire North Project. However, the North to South path, which has a single contract that dates back to the original construction of the connector in 2008, has not been economic for some time. That contract term ends this December, and given the current market dynamics, we don't expect to renew it at existing rates. While this is not a surprise, it will likely have a significant impact on next year's pipeline revenues. The full annual value of the contract is $19 million, of which $14 million falls within fiscal '19.

Empire can file a rate case at any time, and we are currently evaluating the timing of any such filing. In spite of this issue, we continue to be optimistic about the long-term future of our Pipeline and Storage business. As Ron mentioned earlier, we are still on track with our Empire North Project, and anticipate an in-service date early in fiscal 2020. This should add approximately $25 million in annual revenues.

In addition, while the legal process related to the Northern Access Project is playing out, we continue to explore additional transportation tiles to get Seneca's production to market, and are confident we will find a solution.

Lastly, we continue to make investments to modernize our system. Over the past 5 years, we've invested more than $150 million in such efforts. Looking forward, we have some large-scale projects on the table, perhaps as much as $350 million over the next 5-plus years.

Fiscal '19 will likely be a down year for the Pipeline business as a result of the connector contract, but we are confident that for 2020 and beyond, our continued investment in system modernization -- and system expansion and modernization projects, will deliver meaningful long-term growth in rate base and earnings.

Earnings -- to earnings guidance. While we're revising our range to $3.20 to $3.40 per share, this amount excludes the $1.29 per share impact of remeasuring our deferred taxes.

Last night's release highlights the specific details of our guidance. John already commented on the production forecast, but I'll hit on a few of the high-level drivers.

On the heel of sustained oil price increases, we've revised our WTI oil price assumption to $60 per barrel, up from $50 a barrel last quarter. Additionally, California Oil continues to be highly correlated to Brent pricing, and with the Brent WTI spread widening, we've revised our California basis differential assumption to 98% of WTI, up from 95%.

For our Appalachian gas production. We're holding our NYMEX assumption constant at $3 per MMBtu, but have reduced our spot price assumptions to $2.40 for the remainder of the winter months, and $2 dollars for the summer. Previously, we had assumed $2.40 for the entire fiscal year. While spot pricing in Appalachia has seen a nice uptick since our last earnings call. It has a history of volatility, particularly as we get into the shoulder months of the heating season. We continue to layer in firm sales to match our production profile, mitigating some of this volatility, but there will always be an element of spot sales in our forecast.

As new takeaway capacity comes online and local markets evolve, we'll continue to evaluate our pricing assumptions. For reference, a $0.25 change in NYMEX equates to $0.05 per share of earnings, and $0.25 change in basis differentials equates to about $0.02 per share of earnings.

From a unit cost perspective. With the service cost inflation that John discussed, we now expect Seneca's DD&A rate will trend towards the higher end of our original range, and therefore, we're revising our forecast to be about $0.70 for the full fiscal year. All of Seneca's other unit cost assumptions remain unchanged.

On the capital spending side, our new guidance is $560 million to $650 million at the midpoint, $15 million higher than last quarter. The only significant change relates to Seneca's service cost inflation that John mentioned earlier. The rest of the businesses are still trending within our original ranges. For the year, we expect our capital spending will be in line with our cash from operations.

In summary, the first quarter was a solid start to the fiscal year. Federal tax reform was a real plus for the quarter, and should continue to benefit National Fuel in the years to come. We continue to focus on growing the business over the long term while maintaining the strength of our balance sheet.

And with that, I'll turn it over to the operator and open the line for questions.

(Operator Instructions) Your first question is from Holly Stewart from Scotia Howard Weil.

Maybe just the first one for John. John, I think, last quarter, you talked about the potential to add another frac crew maybe in the back half of the year. Just kind of given the movement in the development schedule that you referenced within the release, can we get an update on, really, just the thinking there?

Sure. Yes, we -- what we're going to -- what we will end up doing is using a spot crew when we're completing wells in Lycoming. We already have done that on our first pad there. We're drilling 2 additional pads, and we'll use a second spot crew to -- for that activity as well. So we'll keep a single crew in the WDA, but we'll use it -- we'll have a spot crew out East when we're completing wells.

And those rates for those crew is pretty comparable to what you're already paying?

A little more expensive, but actually, not as bad as we thought they were going to be.

Okay. And then, maybe, another one for you. Just looks like there's been some recent A&D activity in the Northeast and looks like there are others expecting to be marketing packages. Any appetite for Seneca to get a larger position up there?

Yes. And especially in our Eastern -- in the EDA, we do -- we certainly have an appetite. And so when opportunities arise, we definitely review them. And right now, we haven't seen any formal sales processes happen. But it is -- there are opportunities that we'd be interested in.

Okay. Great. And then, maybe one for Dave. Dave, I think you mentioned $350 million, if I had that written down right, of pipeline projects over the next 5 years. It looks like Empire North is $140 million of that. Any color you can provide at this point on anything larger?

Well, the $350 million that I referred to, Holly, is the amount we expect to spend on modernization projects. So you think of our system as an older one, with pipeline going back into the 40s and 50s. And over time, that has to be upgraded and replaced. And we've done quite a bit of that over the past few years and have got a decent backlog of what's going to be larger projects off into the future.

Okay. So it's more (inaudible)...

And over time, it will grow a rate base.

The next question is from Graham Price from Raymond James.

Just wondering how much of the service cost inflation that was mentioned in the release was kind of on the completion side? And then, from what you've seen what the market looks like, as far as entering long-term service contracts, and kind of walking in some of that pricing going forward?

Yes. Good question. We've seen increases across -- basically, across all of our costs. Certain, the pumping pressure services is definitely the highest that we've seen. It's the biggest piece of our drilling completion cost, and so it has the most impact. Most of our contracts, historically, have been fairly long, 1-year plus. As activity is increased, those contract terms have been a little bit shorter. And so we'll see as we go forward, we'll see what kind of increases or whether we're able to keep it flat.

Okay. Great. And then, for my follow-up, of the wells that were delayed into 2019, I was just wondering if we could get a little color on where those are located.

Say that -- I'm sorry, I missed the question. Ask that again?

Sure. The -- I think there were a few completions that were delayed from 2018 into 2019. Just wondering where those were located?

Yes. Yes. Those will be a little bit of delay at 007, and then, a little bit at Lycoming.

Your next question is from Chris Sighinolfi with Jefferies.

Dave, just wanted to start the -- if I look at, obviously, appreciate the color you offered last night and today, with regard to the tax impacts. And obviously, I also appreciate that there are some elements to what the policies, sort of formal implications might mean and are still unresolved. But as I pivot to the cash tax line and think about what you've historically been paying in terms of cash taxes, I know you've called out federal AMT as being part of that. But I'm just wondering if you can help us, maybe, narrow down what your expectations are if we think about, historically, what you were paying? And sort of the rate implied? What might happen to that on sort of the near or intermediate term?

Well, in the real near term, I don't see there being any impact because we still have a decent-sized NOL that will offset any tax payments for this year. Because of a cork in the way, the transition rules work will still be subject to AMT this year, in '18, but that will be a relatively small dollar amount. As we move past 2018 into '19 and '20, we're still doing a lot of the modeling around this. And as you pointed out, things can change, but I do expect that directionally, we'll be better off from a cash flow standpoint. When you look at the ability of the nonregulated businesses to take 100% depreciation in Year 1, that generates quite a bit of deductions. Our Utility and Pipeline will go back to makers, and will have a good amount of taxable income, we think. Because we filed a consolidated return, we're able to effectively capture the value of the accelerated depreciation on the non-rag side. So when you blow away all the smoke, I don't know that I can give you a specific number, but directionally, we'd expect to be better off cash flow-wise.

Okay. And then, I guess -- and this is maybe an unfair question, but I'll ask it anyway because we have to think about sort of terminal states in the worlds long into the future. But I guess, given the nature of the change and the step down in the federal rate, I mean, where would you think that we should mark sort of a long-term cash tax rate for you with federal and state? And with the myriad of sort of different businesses that you guys have, assuming the portfolio would remain static?

Yes. I would say in the mid-20s, is what my -- our tax guy is telling me. But we, like I say, Chris, we are still modeling this so I -- we'll keep you updated as we go through that process.

Listen, I appreciate -- I think, everybody on the line appreciates the fact that it's early days and it came together late in the year, and there's so many parts that move and may be offset. So just the initial thoughts are helpful, Dave. I guess, switching gears, I was also thankful for the update on the Southern, I guess, Southbound service on Empire. Just wondering, what are the options with that capacity? And if you could walk us through -- I mean, obviously, you don't expect the contract to renew, certainly not at the existing rate. But what, I guess, what is the decision tree with what to do with that? And what options are available?

I think it's pretty simple, that we'd like to try and market the capacity in some way. I mean, we have the ability to discount rates. So certainly, that would be a preferred option. If we're unsuccessful in doing that and show our revenue requirement, we can file a rate case.

Okay. And with respect to rate case, you had talked about the modernization efforts. So you were talking about that just a moment ago with Holly. Is the recovery on that spend requiring a rate case action on the systems? Or are there built-in sort of tracking elements that you will capture in some of that spend?

Yes. Well, we have a requirement and supply company, which is where the -- all of the modernization dollars are. There's really none on Empire. We have to file a rate case in supply by the end of 2019. So we'd look to that event, if you will, as a way to recover some of that modernization spending.

The next question is from Tim Winter with Gabelli & Company.

I was wondering, Ron, if you could talk a little bit more the logic and outlook for FERC to rehear the Northern Access application? And should they approve, what other obstacles would be there? And would New York have any recourse?

Sure. Tim. Well, as you know, we already submitted our request for rehearing on that. And if you were going to try to get any read-through from FERC's action on the constitution's request for rehearing, which -- that order came out January 11, I believe. We always, as we always point out, facts are different in each one of these cases, and as it is with ours, we're different than Constitution. And given the fact that there's been this much time between what they did in Constitution and have enacted on ours yet, you can indicate that we are -- hopefully, getting a different answer. So you move on from that, and taking your premise that FERC grants our rehearing, and indicates that the DEC took too long, obviously, DEC could go try to appeal that, request rehearing again. I'm not sure of the absolute procedural steps they would take, but given what we've seen in the Valley lateral, the Millennium case, I would expect that you just see more litigation attempted from the state side.

There are no further questions at this time. I will turn the call back over to the presenters.

Thank you, Mike. 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 9. To access this replay online, please visit our Investor Relations website at investor.nationalfuelgas.com. To access by telephone, call 1 (800) 585-8367, and enter the conference ID number 8999277.

This concludes our conference call for today. Thank you. Goodbye.

This concludes today's conference call. You may now disconnect.