National Fuel Gas Company (NFG) Q4 2017 Earnings Report, Transcript and Summary

Good morning, my name is Kelly, and I will be your conference operator today. At this time, I would like to welcome everyone to the Fourth Quarter 2017 National Fuel Gas Company Earnings Conference Call. [Operator Instructions] Mr. Brian Welsch, Director of Investor Relations, you may begin your conference.

Thank you, Kelly, 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 fourth quarter fiscal 2017 earnings release and November 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 Jefferies Energy Conference later this month in Houston. 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 it over to Ron Tanski.

Thank you, Brian, and good morning, everyone. Thanks for joining us today. Our 2017 fiscal year was another strong year for National Fuel, both earnings-wise and operationally. Each of our main operating segments posted strong earnings that were in line with our projections and Dave Bauer and John McGinnis will give more details about segment earnings drivers later in the call. As we noted in the guidance section of the release, earnings for 2018 fiscal year are forecasted to be down slightly, in large part, the decreased results from lower realized commodity prices in our Exploration and Production segment, where the higher priced financial hedges that we had in place have rolled off. Forward strip prices remain relatively flat in a $3 per MMBtu strip price and a $2.40 per MMBtu spot price where our natural gas production have been built into our forecast for next year. While this flat pricing appears to be the new normal and resets the base of our pricing assumptions moving forward, we illustrate in our Investor Relations slide deck that our drilling program remains economic in this environment. Unfortunately, we'll be missing the boost to earnings that we had expected from our Northern Access Project, which has been delayed. In our second circuit litigation against the New York DEC, oral argument for our case has been scheduled for November 16. If we were to use the Constitution lawsuit as an indicator of the time line, we may not get a decision from the court until August. Remember that the facts in our case are different from the facts in Constitution and we're not discouraged by the outcome in that case. As you know, we're also awaiting FERC action on our request for rehearing with respect to our waiver argument regarding New York's action -- or more appropriately, inaction on our water quality permit application. It's hard to project a time line for an answer on that rehearing since FERC seems to be busy clearing up their certificate application backlog that built up when they had no quorum. Add to that the additional litigation that the New York DEC is piling on in the Millennium Valley lateral proceeding and it's anyone's guess when we might get an answer. We are encouraged, however, that FERC will have a full complement so commissioners with yesterday's Senate Confirmation of the last 2 commissioners. I believe that FERC's staff never really slowed down on their standard workload during the administration turnover, but it will be good to have a complete slate of commissioners so that major policy issues can be addressed. In the meantime, Seneca continues its plan to delineate our Utica shale acreage in the Western Development Area. We've also resumed drilling in our Eastern Development Area in order to hit plenty of production available that flow into Transco's Atlantic Sunrise project. As we noted in our guidance section in the release, we project that Seneca's production next year will be in the range of 185 billion to 200 billion cubic feet equivalent, approximately a 10% increase in production over fiscal 2017 and we will accomplish this while generally living within our projected cash flow. We continue to have discussions with others regarding joint projects that could provide an outlet for Marcellus gas of Seneca and others, where the project would take a path that avoids the permitting pitfalls presented by New York. Nothing is far enough along on this front for me to be in a position to provide any substantive comments today. We are, however, in the process of preparing our FERC application for our Empire North project. While this project does provide for additional volumes of natural gas to flow into New York, we've designed the project to primarily be a compression project. We believe that the construction activities involved for Empire North won't require a water quality certificate from the state since the project is designed to increase throughput on our existing Empire Pipeline system. As a reminder, this project will add 205,000 decatherm per day of throughput at a capital cost of $135 million and is expected to come online in November of 2019. We expect fiscal 2018 to be another year where we'll be living within cash flow. Our $535 million to $645 million capital expenditure program that we have summarized in the release will continue to focus on growth across the company. Our ongoing system modernization program in the regulated segments will continue to increase rate base in those segments and will continue to increase Seneca's production through the ongoing development of Seneca's reserves, both in the Utica shale and in the Marcellus shale. The Utica development will have the add-on effect of providing additional growth in our Gathering segment. The Marcellus development in the Eastern Development Area will utilize existing Gathering facilities and will be used to fill our Atlantic Sunrise capacity when that comes online in mid-2018. In summary, we're busy in each of our operating segments and each one is moving in the right direction for fiscal 2018. Now John McGinnis will give an update on Seneca's activities.

Thanks, Ron, and good morning, everyone. Seneca produced 40.4 Bcfe during the fourth quarter compared to 39.8 Bcfe in last year's fourth quarter. Total annual net production was 173.25 Bcfe this year. That is a new annual high for Seneca and was an 8% increase year-over-year and a total of 10% over the past 2 years, even while dropping to 1 rig from much of that time and entering into a joint development agreement where Seneca's working interest was reduced to 20%. Additionally, Seneca has generated significant positive cash flow each of the last 2 years, all in spite of weathering a tough commodity price environment. We achieved this through a combination of best-in-class Marcellus well costs, a joint development agreement with IOG and continuing to follow a disciplined risk management approach by locking in prices physically and financially when opportunities arise. Moving forward, we should continue to be cash flow neutral to positive over the next few years, even with our forecasted 10%-plus average annual production growth, as we execute on our long-term development plans. Our production growth for the year was largely driven by stronger-than-expected Marcellus well performance, including better-than-projected flush production rates as we brought on previously curtailed wells and minimal curtailments due to the improved strength in the spot market. For the year, we curtailed a total of 6.2 Bcf net compared to 34.6 Bcf last year. Much of these curtailed volumes actually occurred very early and very late in the fiscal year. Our capital expenditures totaled $246 million, an increase of $147 million compared to last year. The key drivers for this increase included lower year-over-year upfront and working interest proceeds associated with the IOG joint development agreement, bringing on a second rig in May and drilling and completing a greater number of 100% working interest wells. In Pennsylvania, we have now drilled all 75 Marcellus wells in our IOG joint development and we're currently completing the final 12-well pad. This final pad should be online sometime during our second quarter. For the year, our proved reserves increased by 305 Bcfe or 17% with a total of around 2.15 Tcfe. This increase was primarily due to 2 key factors: reserves added from our Pennsylvania development program and positive reserve for revisions as a result of improved pricing. Only 28% of our proved reserves are currently categorized as proved undeveloped. Utica reserves now account for nearly 10% of our total, and as we move forward with full development in both the Western Development Area and on our Tioga 007 Tract, this percentage will grow quickly. And finally, we continued to reduce our 3-year average F&D costs. Our 3-year average is now at $0.98 per Mcfe, and this reduction was driven by a combination of improved drill bit F&D and positive price revisions given the higher prices both in Pennsylvania and California. Going forward, this number should continue to decrease as Pennsylvania becomes a greater overall percentage of our capital program. We now have 8 Utica wells on production in the WDA and we will be shifting to 100% WDA Utica development program by the end of this fiscal year. Our 3 new wells have been online for less than 30 days and they have not yet reached peak production as a result of our conservative drawdown management program, bringing these wells online slowly. Early indications suggest, however, that they will be similar on a per foot basis to our previous appraisal wells, and therefore, we have now generated an initial WDA Utica type curve based on the first 5 wells. This type curve was included in our IR deck last night, along with our CRV Marcellus type curve. Our Utica type curve assumes an EUR of 1.7 Bcf per thousand foot compared to 1.1 Bcf per thousand foot related to our CRV Marcellus wells. To date, all of our WDA Utica wells exhibit very shallow declines as compared to our Marcellus wells, and so far, we've been very pleased with the results. In California, we produced 674,000 barrels of oil during the fourth quarter, up very slightly from the third quarter. Annual net production in California was down about 5% year-over-year to 3.2 MMBOEs. As I stated last quarter, this decrease was primarily due to changes in our steam operations and a significant reduction in well workover activity as a result of low oil prices. During the fourth quarter, however, our oil production has increased by around 300 BOEs per day as we ramp up our workover activity. In tandem, total LOE also increased $4.6 million this quarter or $0.10 per Mcfe on a per unit basis, driven mainly by this increase in workover activity and due to increased steam fuel cost. We will see higher LOEs through the remainder of the first half of the year as we continue to bring on idle wells in California. And these costs, however, should return to more typical numbers by the end of our second quarter. For fiscal 2018, we are forecasting capital expenditures to range between $275 million to $325 million. California ranges between $30 million to $40 million and Pennsylvania between $245 million to $285 million. We will remain at a 2-rig pace in Pennsylvania with 1 rig active drilling both Marcellus and Utica wells in the WDA and the other rig drilling Marcellus wells in Lycoming and Utica wells in Tioga. For much of the year, we will remain at a single completion crew, but at times we will need to bring in a second crew. Net production is expected to range between 185 to 200 Bcfe, a forecasted increase of around 10% year-over-year. Our fiscal '18 production forecast, however, assumes minimal curtailment through the remainder of the year. We enter fiscal '18 with the pricing for 96 Bcf or 55% of our production locked in physically and financially at a realized price of $2.59 per Mcf. We currently estimate that we'll sell around 32 Bcf into the spot market. But obviously, depending on pricing, these volumes are at risk for curtailment and would reduce the forecasted production range just discussed. Finally, in California, we're forecasting production to be around 3.3 million MMBOEs. 60% of our oil production is hedged at an average price of $54.30 per barrel. And much of our development activity this year will continue to focus in Midway Sunset, both on our legacy properties and on our new farm-in opportunities at Pioneer in South Midway and 17N in North Midway. The key risk related to the start-up of these programs is obtaining aquifer exemption approval to allow us to begin injecting steam into these reservoirs. The approval process has been slow, but once we obtain the necessary permits, we'll move forward quickly. And with that, I'll turn it over to Dave.

Thanks, John. Good morning, everyone. Last night, National Fuel reported fourth quarter earnings per share of $0.53. While this was lower than the $0.66 per share on last year's fourth quarter, earnings were right in line with our projections. For the full fiscal year, operating results were $3.30 per share, an increase of 7%. The earnings for the quarter at the regulated subsidiaries were pretty straightforward. The only item of note was O&M expense in the Pipeline & Storage segment, which was up $3.4 million over last year. During the quarter, we incurred about $1.5 million in cost to overhaul 2 major compressor units. While overhauls themselves aren't unusual, we typically don't have 2 in 1 quarter. We also saw an increase in project development costs, mostly related to the Empire North project. As you'll recall, we gave conservative approach with respect to these costs and expensed them in the early development -- early stages of development. At Seneca, production for the year was a little below the midpoint of our guidance. In the latter part of the quarter, spot pricing in Appalachia dropped significantly from levels we saw earlier in the year. Not only did this reduce price realizations relative to forecast, but it also led us to curtail 2.5 Bcf of production during the quarter, which in addition to impacting Seneca's production, had a follow-on effect on our Gathering business. Spot prices have remained depressed throughout October. But as cold weather returns and as new infrastructures added in the basin, we expect prices will recover. There were a couple of unusual expense items during the quarter at Seneca that we don't expect to repeat. First, LOE came in as $1.07 per Mcfe, which was meaningfully higher than in prior quarters, but it was generally in line with our projections. As John mentioned earlier, this increase was largely due to the timing of workover activity in California, which was back-weighted to the third and fourth quarters. Looking at next year, we expect LOE to return to the $0.90 to $1 per Mcfe range. Second, Seneca's other operating expense for the quarter reflects a $2.4 million payment to reimburse a Canadian pipeline operator for costs related to a project to develop new capacity downstream with Northern Access. That payment essentially puts the development of the Canadian capacity on hold, ending the approval of Northern Access. Once that happens, development of that capacity will recommence and Seneca will recoup the $2.4 million payment. Lastly, our consolidated effective tax rate was significantly lower than prior quarters. This was driven by 2 main factors. First is an adjustment to Seneca's Pennsylvania deferred income tax liability that is related to its capacity on Atlantic Sunrise. As a result of that project, more of Seneca's production is expected to be transported out of Appalachia, and therefore, less of its income will be taxed in Pennsylvania. This allows us to reduce Seneca's PA deferred tax liability, which benefited Seneca's effective tax rate for the quarter. We had a similar adjustment a few years back related to our Northern Access 2015 capacity. Second, with oil prices at current levels, we're able to take advantage of tax credits related to enhanced oil recovery activities at our California operations. These credits are available on a year-to-year basis depending on historical oil prices. This credit will apply again in 2018. But if oil prices rise in the future, it will phase out. Our fiscal 2018 guidance assumes an effective tax rate in the range of 38% to 38.5%. On the tax reform front, yesterday, the Chairman of the House Ways and Means Committee released a 429-page Tax Cuts and Jobs Act. This bill includes a substantial tax rate reduction from 35% to 20% as well as many other changes to the tax code. Our initial take on the proposal is positive, but it obviously has a long way to go before becoming law. There are 2 other items of note that occurred during the quarter. First, we refinanced $300 million of 6.5% interest rate notes that had been scheduled to mature in April 2018. To do this, we issued $300 million of new 10-year notes that carry a rate of 3.95% and executed the make-whole option on our 2018 maturity. This transaction was well received in the market and will translate into meaningful interest savings. However, because the 2 components of the refinancing straddled fiscal years, at September 30, both cash and long-term debt on the balance sheet are temporarily inflated by $300 million. The call of the 2018 bonds settled in mid-October. So as of today, our long-term debt is back to $2.1 billion. In the Pipeline & Storage segment, FERC recently approved a surcharge related to new pipeline safety and greenhouse gas emissions regulations. As part of Supply Corporation's 2015 settlement with our shippers, parties agreed to a recovery mechanism that became available if costs related to new regulation exceeded a certain threshold. We reached that threshold, and therefore, filed and received approval for a surcharge that will add about $4 million in additional revenue next year. We had taken this item into account when we established initial guidance. As a result, there isn't any change to our Pipeline & Storage revenue forecast, which remains at $295 million. Turning to guidance. Aside from the items I touched on earlier, not much has changed since our initial fiscal 2018 projections we provided last quarter. We're modestly tightening our earnings guidance to a range of $2.75 to $3.05 per share. This increase is largely the result of lower expected interest expense as a result of the bond refinancing. Detailed assumptions are included on Page 7 of last night's earnings release as well as in the appendix of the Investor Relations deck. Our NYMEX assumptions of $3 for natural gas and $50 for oil are unchanged. We're starting the new fiscal year 60% hedged for oil and 55% for gas. This is right in line with our policy and we'll continue to look for opportunities to layer in additional hedges as the year progresses. A fair amount of our unhedged production are volumes that will flow into our Atlantic Sunrise capacity. Construction of that project has begun. And as we get more clarity on the exact in-service date, we'll look to layer in additional trades. The midpoint of our 185 to 200 Bcfe production guidance range assumes we sell about 32 Bcf of spot volumes in Appalachia at an average price of $2.40 per MMBtu. This is higher than the prices we have seen over the past few shoulder months, but as I mentioned earlier, we expect that colder weather and additional pipeline capacity will benefit prices in the basin. So for now, we're going to keep that spot price assumption the same. To give you a sense of the potential impact on earnings, if actual spot pricing differs from our assumptions, we would expect earnings to be lower by about $0.055 per share for every $0.25 per MMBtu change in average spot prices. Looking at capital spending, our guidance of $535 million to $645 million is unchanged. For the year, we expect cash from operations to exceed doubtful spending by about $50 million at the midpoint of our guidance. This is consistent with our goal of living within cash flows for the next 3 to 5 years. In conclusion, National Fuel is in a very good position. At a 2-rig program, we expect to grow our Upstream and Gathering businesses by 10% a year for at least the next 3 years, all well living within cash flows. On the regulated side of the business, pipeline development opportunities, combined with the ongoing need to modernize our system, will contribute to long-term growth in rate base. Our balance sheet is strong and should continue to strengthen, providing flexibility to pursue additional opportunities as they arise. With that, I'll turn it over to the operator to open the line for questions.

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

Maybe first for John. If you could just give us a sense of -- I think you said in 2019 that the WDA would be just specific to Utica development, but give us a sense this year in 2018 in both the WDA and EDA, kind of the split there between Marcellus and Utica. And if you've got well count numbers, that will be great.

Sure. As I mentioned in the discussion just now, we still have 3 wells that are currently coming on and we will be drilling 3 more wells, I think, for the -- at least bring in 3 more wells online during 2018 in the WDA area. So we'll be doing some drilling. I don't have that drill count now, but I know we'll be bringing on 3 additional wells. Out East, once we're done in Gamble, we'll be moving to Tioga on our first pad there and I believe it's 7 wells that we'll be drilling on that pad, and that will all take place during this fiscal year. We won't see production from that until 2019. I believe we head there in the second quarter.

Okay. And then another one just on Atlantic Sunrise, if you could maybe help us just understand how you envision that project filling up. Is it 100% full on day 1? Is that existing production versus incremental production? Just trying to think about how you utilize that project from the get-go?

Yes. It'll be full on day 1. We have existing production there now, could fill it today. And we're projecting that it comes on in July. And if we see that it's going to slip a little bit, we may be out in the market trying to fill that gap. But as of today, we could fill it from day 1.

Okay, great. And then just one final one from me and Dave referenced it in his comments, but just wanted to follow up. Assuming at this point, given where we are in the spot market, we are still curtailing volumes for 1Q?

Yes.

And your next question comes from the line of Graham Price of Raymond James.

Just real quick on the Utica test wells. Just wanted to get a sense of maybe how much testing is left with regard to determining optimal proppant loads and stage spacing, things like that. And then any potential uplifts to EURs that we could see from that?

Yes. A quite a bit of testing is left to do. For example, in the 3 most recent wells, we actually tested 3 different targets. And they're all within 30, 40 feet of each other, but we've actually seen differences even with that small of a change. As we move forward, we will -- it will be an ongoing, I guess, testing program. We will be changing -- at least into for the next year, we'll be testing different stage spaces -- spacing. We'll be testing different well spacing as well. So still quite a bit of work to do. And in terms of improving these well results significantly, I don't think that will happen. It's more towards fine-tuning and cost-saving.

Okay, got it. That's great. And then real quick for my follow-up, just wondering about completed well costs for those 8 Utica wells that have been drilled. I know that these costs will be coming down, but just kind of wanted to get a sense of maybe where you're at today.

Well, overall, they're about 20% higher and most of that is on the completion side. I don't know what they are today, but I know we're expecting, on the completion side, they'll be a little north of $3 million once we move into full development.

Okay. And you expect to move to full development kind of late 2018?

Yes. Yes, towards the end of 2018 moving into 2019, we will have fine-tuned our completion practices and be moving forward on that.

Your next question comes from the line of Becca Followill of U.S. Capital Advisors.

Just following up on that question. I think you said it's $3 million for completed well costs for just the completions portion?

It will be a little over between $3 million and $3.5 million.

And then the drilling portion?

We're estimating a little over 2 -- between $2 million and $2.5 million. So in all-in, between $5.5 million to $6.5 million, I think we're looking at $6 million, $6.2 million.

And that's where you expect to be?

That where we expect to be. It's a little more expensive now because we do a lot of science on these pads -- on these wells. Our stage spacing is tighter than what I think it'll end up. So there's still a lot of work to do, but it will reduce as we go forward.

How long do you think to get to that level?

Within a year, 9 months to a year.

And targeted well spacing at this point?

Good question. Probably minimum, 1,000 foot. But I think we'll probably start a little wider that, around 1,200. But that's something we are still working out.

Great. And then last question is, can you tell us how much gas was curtailed during October?

About 1.5 Bcf.

And your next question comes from the line of Tate Sullivan of Sidoti.

Can you go into more detail on your utility, just in terms of the customer growth rates year-over-year? I think it declined slightly in Pennsylvania, and give some context for those rates of growth?

Sure. Our -- as you know, we've got a pretty high concentration of the customer base in both New York and PA at better than 95%. There is some population growth, but we don't count on large growth in customer count, probably in the 0.5% area per year.

About 0.5% percent per year?

Yes.

Okay, great. And then the year-over-year decline in the quarter in the utility, was some of that weather related in Pennsylvania or was it mostly the lower rate case coming through in New York in April?

So you're saying the earnings of...

For just the utilities.

Quarter-over-quarter?

Year-over-year?

Oh, year-over-year. Yes, the biggest chunk of that is going to be weather in Pennsylvania, which was -- I think the winter was somewhere around the 10% warmer than normal area. On top of that, we had some costs creep in the OEM side, but weather was, by far, the biggest factor.

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

Dave, I just had a question with regard to the timing of that deferred tax liability reassessment. Was that due to something within the regulatory approval process for Atlantic Sunrise or the fact that you're [ heading ] a fiscal year or something else? Just what -- I guess, what made you take a reassessment at this point?

So this is with respect to the Atlantic Sunrise adjustment?

Yes. Your PA tax going down.

Yes, you got to pick a time when we make the adjustment. We've typically been pretty conservative and waited until we've seen shovels in the ground to make the adjustment. So with construction pretty much underway on Atlantic Sunrise, the probability of that project being completed was high in our estimate and that led us to record the adjustment.

Okay, okay. That's helpful. And I guess, what would be next steps for Empire North? I did see some incremental precedent agreement volumes added, I think, since the last call. And you had obviously mentioned in prepared remarks some additional expensing items associated with that project this past quarter. So I'm just wondering what milestones to look forward to, to [ strip date's ] progress on that and potential time line for it?

Yes. The next steps would be the actual filing of the FERC application for the 7(c) for that project, Chris, and that's basically it. The spending to date has been preliminary engineering for the compressor sites and logistics for that. So we're looking to get that done pretty close to the end of the year. And as a matter of fact, we're starting outreach hearing or outreach meetings next week to cover any questions that locals might have with respect to the siting of those compressor sites.

When -- Ron, when you say the end of the year, you mean this calendar year?

Yes, the calendar year, yes. I'm sorry.

Just being -- okay. And with -- I guess, with regard to the precedent agreements in place on that project, are those both third parties or a Seneca represented at all on that front?

No. Seneca is not represented. So a portion of it, however, is our utility and I forget the exact portion of that, Dave. Do you...

Yes, it's relatively small.

Yes, it's a relatively small. But it's a third-party production that would be utilizing that space.

Okay. Two more questions, if I could. One was, Dave, if I heard you correctly with regard to the payment made, I guess, that was to TransCanada just to keep on ice for some time the ability to carry the Northern Access volumes all the way into [indiscernible]. Is that right? Is that sort of how to understand it? Then if Northern Access does eventually go forward, they complete their portion of the build, you get reimbursed?

That's exactly right, Chris. It basically suspends the project until we get approval on Northern Access.

Okay, okay. And then, I guess, a final question from me is just there's -- there was a shareholder proposal or idea floated about tracking stock potentially for your utility company. And then I have my own thoughts about it, but I was just curious if you guys had obviously considered that and thought about it either amongst the management team or conversation at the board level and what, if any, response or thought you've given to that.

Yes. It's a little tough to comment on that right at this point in time, Chris. We're in the process -- yes, the lawyers are concerned about anything we say being considered proxy solicitation. So I'd just prefer not to comment on it at this point.

[Operator Instructions] And there seems to be no further questions at this time. I turn the call over to the -- back to the presenters for closing remarks.

Thank you, Kelly. 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 10. To access the 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 96083185. This concludes our conference call for today. Thank you, and goodbye.

And this does conclude today's call. You may now disconnect.