National Fuel Gas Co (NFG) 2016 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the National Fuel Gas Company Q3 2016 earnings call. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions). As a reminder this conference is being recorded.

I would now like to introduce your host for today's conference, Brian Welsch, Director of Investor Relations. Sir, you may begin.

Thank you, Jamie, 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 is 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 third-quarter fiscal 2016 release and the 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 on which they are made and you may refer to last evening's earnings release for a listing of certain specific risk factors.

I would also like to point out that the Company is planning to participate in the EnerCom Oil & Gas conference in Denver in 2 weeks and the Barclays CEO Energy Power Conference in New York City in September. If you are planning on attending, please contact the respective conference officials or me directly to schedule a meeting with management. We look forward to meeting everybody there. With that I'll turn it over to Ron Tanski.

Thank you, Brian. Good morning, everyone, and thanks for joining us today. National Fuel's earnings report last evening reflected a very good quarter of operations across all our subsidiaries.

I'll let Dave Bauer and John McGinnis talk about the drivers of the quarterly earnings for our major segments in a few minutes.

Now, another quarter of steady operating results might make it appear that there is not a lot of that we have going on. I can assure you that that is not the case.

In our upstream exploration and production segment, Seneca Resources extended its joint development agreement with IOG resources for a second block of Marcellus wells. That agreement allows us to continue our acreage development program, but it also reduces our capital requirements and allows us to share some of the development risk with a third party.

We also have some exciting early results in our Utica Shale appraisal program.

Finally, we've seen some firming pricing in the Basin that allowed us to increase our spot sales of natural gas during the quarter. In our utility segment we converted to a new customer information and billing system during the quarter. We invested over $50 million and spent a lot of development time to get things right and our conversion went very well.

It's also been an excellent construction season in our service territory. And we are well along meeting our targets for our mainline and service renewal program. Those system upgrades help us assure the continued safety of our pipeline system and meet the pipeline renewal mandates of the public service commission.

All these investments -- in fact, all these investments we have made in the utility over the past nine years since our last New York rate case in 2007, had put pressure on our earnings, and we filed a rate case in our New York service territory at the end of April. As you all know, state rate proceedings take a fair amount of time.

Our rate team has been very busy answering the hundreds of data requests and interrogatories from the Public Service Commission and new rates wouldn't go into effect until next spring.

In our pipeline and storage segment, at the federal level, we did reach a settlement in our Empire pipeline rate proceeding with our customers and staff at the Federal Energy Regulatory Commission. We filed the settlement agreement a few weeks ago.

While that document is waiting formal approval by the Commission, we've gone ahead and put Empire's new settled rates into effect as of July 1. Our earnings guidance that we included in last evening's release reflect the settlement of that case.

Also in the pipeline and storage segment, we are pleased to report that FERC issued its environmental assessment, or EA, for our Northern Access project. The EA noted that if we follow our construction procedures and mitigation techniques, our project will result in no harm to the environment. We think this project is an important addition to the infrastructure in New York. We will make additional supplies of low-cost domestic natural gas available in the state and neighboring areas.

The New York Independent System Operator recently released a report indicating that power plants fueled by natural gas, or that are dual-fueled, provide 57% of the electric power generation capacity in the state. And that natural gas and dual-fueled projects make up 65% to 70% of the new generating capacity that is being studied for interconnection to the grid.

Clearly if we are going to keep the lights on in the state, new natural gas pipeline infrastructure will be necessary to supply those generating plants. We've been having ongoing discussions with the New York Department of Environmental Conservation regarding our water quality certification, and necessary air permits for the project. Things appear to be moving along and our schedule anticipates receiving our FERC certificate this fall and our water quality certification and air permits in March of 2017.

For our Empire North project, we are continuing to work on proceeding agreements with shippers for the 330,000 dekatherm per day of capacity for that project. It's taking some time to sort through the various combinations and permutations of capacity requests to various delivery points, and how the new capacity can be integrated with the existing capacity that some of the shippers already have. We expect that this project will have a fiscal 2019 in-service date following the fiscal 2018 in-service date for the Northern Access Project.

Following our usual practice the information deck that we put online last evening has a lot more detail regarding our operations, forecast and assumptions. You can refer to those materials at your leisure particularly the information regarding our gathering segment and the link that it provides between our upstream production and the midstream pipeline operations.

We've got a lot going on in all our segments and it's all working very nicely together according to our integrated plan. Now I'll turn it over to John McGinnis.

Thanks, Ron, and good morning, everyone. Seneca produced 44 Bcfe during the third quarter, an increase of 4.8 Bcfe or 12% compared to the second quarter. In Pennsylvania, we produced 38.8 Bcf of gas, an increase of 14% from the second quarter. This increase in production was due primarily to additional firm sales and improved spot pricing on both our Transco and TGP receipt points.

Although prices have fallen off recently, over the quarter we were able to sell around 6.4 Bcf net into the spot market. And for the remainder of fiscal 2016, we have 34 Bcf of our forecasted gas production tied to firm sales at an average price of approximately $3.10 per MCF.

In California we produced 722,000 barrels of oil during the third quarter, essentially flat third quarter over second quarter. Production at our largest field, North Midway Sunset, however, is actually down about 500 barrels a day from a year ago due to a lack of sufficient soft water volumes for our steam flood operations.

In order to alleviate this shortage we've recently completed building our own water plant which will initially increase steam levels back to our original volumes and subsequently allow for increased volumes to be added as we move into full development at 17N, a nearby tract we recently farmed into. As a result within the next 12 months we should be able to both increase our daily production in North Midway and have sufficient steam to begin our 17N development.

Moving to our Utica/Point Pleasant appraisal program, our first Clermont Area Utica horizontal well has now been online for just over 45 days. And we are quite pleased with the initial results. We landed this well high in the section within the lower Utica, based upon rock quality, with the understanding that in doing so we may limit our ability to maximize access to gas in place.

Pressure gradients were high across the Utica target in this area, and therefore we brought this well online slowly with control drawdown in order to minimize potential damage to the reservoir. As I stated last quarter, this well was drilled with a short lateral length of only 4,500 feet to better understand productivity on a per-foot basis rather than maximizing production. The well had an IP 30 of around 1,400 MCF per 1,000 feet which is about 60% to 70% higher than our typical Clermont Marcellus wells in the same area.

Over the first 45 days this well has produced over a quarter of a Bcf, and pressures are declining about 60 psi per week and rates about 200 MCF a week. Both quite flat compared to our initial projections.

As a result of this first well we are now planning on drilling six additional Utica wells over the next year, all off our Clermont Marcellus development pads. We've already drilled our second well on a nearby pad and we plan on bringing this well online sometime late this year. We landed the well in the same target but we will be testing a different completion design.

As we move forward with this appraisal program we will be testing different landing zones on some of these wells and we will continue to experiment with our completion designed for this area. In addition as we move to the south and southeast across our WDA fee acreage, Utica depths and subsequently pressures could increase significantly.

Therefore, if the rock quality remains similar, we think there is a good opportunity for even stronger results in the future.

Once we are confident that we can achieve performance consistency with respect to a Utica program, we may elect to move into full-scale development initially for Marcellus pads that are already built and tied into our midstream infrastructure. Since minimal midstream buildout would be necessary, this development program would have the potential to enhance consolidated upstream and midstream returns.

We think we can drill and complete these wells in the $5.5 million to $6.5 million range, depending on lateral length, which implies cost only 30% higher than our Marcellus wells.

Based on our preliminary economics, with the 60% to 70% improvement and well performance, and with only a 30% increase in cost, the Utica may end up being our primary target.

As we announced earlier this quarter, IOG elected to enter into the second phase of our Marcellus joint development program. As a result IOG has committed to participate in a total of 75 Marcellus wells in the CRV area. We've already drilled 59 of these wells, 39 of which are producing. To date, IOG is invested a total of $182 million and we estimate total funding net to IOG's 80% working interest in the 75 wells to be around $325 million.

The bulk of this joint development program should be completed by the end of 2017, or in early 2018. The impact of the IOG joint development program, reduced activity levels, and improved operational efficiencies, have led to a substantial decrease in forecasted spending for both this year and next. For fiscal 2016 we are now projecting our capital expenditures to range between $120 million to $135 million, an almost 80% decrease from the $557 million capital outlay in fiscal 2015.

We are also tightening our production forecast for this year to now range between 160 to 165 Bcfe. We will likely end the year with a WDA DUC count between 60 to 65 wells, ahead of the 2017 Northern Access in-service date. For fiscal 2017, we are forecasting capital expenditures to range between $160 million to $200 million, $125 million to $155 million in Pennsylvania and $35 million to $45 million in California.

In Pennsylvania we plan on remaining at a one rig drill program at least during the first half of the fiscal year. And we will continue with a daylight only WDA frac operation throughout much of the fiscal year. But as startup dates related to both Northern Access and Atlantic Sunrise become clearly visible, we may decide to accelerate both our drill and completion activity accordingly.

Net production next year is expected to range between 150 to 175 Bcfe, essentially flat year-over-year. Natural gas production in Pennsylvania is forecasted to range between 130 to 153 Bcf. Absent the IOG joint development agreement, total production would've grown by around 10% year-over-year. 125 Bcf of forecasted net production has been locked in both physically and financially at an average realized price of approximately $3.05 per MCF.

In addition we have firm sales for another 12.5 Bcf of net production, and therefore we enter fiscal 2017 confident in our ability to sell almost all of our expected production at attractive pricing. In California we are forecasting production to range between 20 to 22 Bcfe. About a third of our oil production is hedged at an average price of approximately $68 per barrel.

In 2017 we will continue to focus on developing both our legacy assets and recent farm-in acreage at Midway Sunset. Our LOE on a per-unit basis is forecasted to increase next year, primarily related to the startup of steam operations on our recent Midway Sunset farm-in acreage. As we grow our production on these properties ,this trend should reverse in fiscal year 2018.

And with that I will turn it over to Dave.

Thanks, John, and good morning. everyone. National Fuel's third-quarter GAAP earnings were $0.10 a share. When you back out the ceiling test charges there some professional fees associated with the IOG joint development agreement, operating results were $0.68 per share, up $0.13 largely because of improved performance at both Seneca and our gathering company, NFG Midstream.

Last night's release describes the major drivers of earnings from year-to-year. But I'd like to add some additional commentary in a couple areas.

First, Seneca's cost structure continues to improve. LOE for the quarter was $0.88 per Mcfe versus $0.96 in the second quarter. We saw reductions in both Appalachia and California. Particularly non-transport LOE in Appalachia came in at $0.12 per Mcfe, down from $0.15, mostly due to the increase in production. In California, work over activity was reduced due to lower oil prices.

In addition, steam operations at north Midway were constrained during the quarter in advance of the new water treatment facility that went in service in late June.

Seneca also saw improvement in its G&A expense. There were a couple of one-time items in the quarter including the $3.2 million of JDA fees and a $1.7 million downward adjustment to a long-term incentive compensation accrual. Excluding the net $1.5 million of expense related to these items, G&A expense for the quarter was $15.1 million, which is about the level of spending we expect going forward.

Per-unit DD&A expense decreased to $0.71 per Mcfe. Most of this improvement was the result of the ceiling test impairment charge we recorded in the second quarter.

Moving forward we expect DD&A to stay in the low to mid $0.70 per Mcfe area, given the significant improvement in F&D costs.

The second major earnings driver is Appalachian pricing. For much of the quarter, basis was presented have been in recent quarters. This combined with a higher NYMEX price contributed to our ability to sell the spot volumes John mentioned earlier, which benefited the earnings of both Seneca and NFG Midstream.

However, National Fuel Resources, our nonregulated energy marketing company, experienced the flipside of the stronger basis as higher-than-expected purchase gas costs squeezed its gross margin for the quarter.

Lastly, our effective income tax rate was unusually high this quarter at 51%. Given the low level of pretax income, minor adjustments to income taxes can have a disproportionate impact on the effective rate.

Looking forward we expect our effective rate to move back to the 38% to 40% area.

Turning to earnings guidance, we now expect fiscal 2016 earnings guidance will be between $2.90 and $3.00 a share, excluding ceiling test impairments, which is up modestly from our previous guidance. This is mostly due to the strong third quarter and lower-than-expected LOE and DD&A at Seneca for the remainder of the year. While our assumed commodity prices have increased, our strong hedge position limits any impact on the fourth quarter. A summary of all our updated assumptions is contained on page 6 of last night's release.

Looking to next year, our preliminary earnings guidance for fiscal 2017 is a range of $2.85 to $3.15 per share. Our guidance assumes a Henry Hub gas price of $3.00 per MMBtu and a WTI crude oil price of $50 a barrel. There's been considerable volatility in commodity prices, most recently with oil, so we may refine our pricing assumptions as we move into the fiscal year.

Having said that, as John mentioned earlier we are well hedged for fiscal 2017, so E&P earnings and cash flow should be pretty well insulated from changes in commodity prices. Seneca's production forecast for next year is 150 to 175 Bcfe. This is a somewhat tighter range than in prior years which reflects the considerable amount of firm sales we have in place. At the midpoint of our guidance, our spot volume exposure is only about 9 Bcfe. From an expense standpoint, the ranges you see on page 7 of last night's release are all based on the 162.5 Bcfe midpoint of our production forecast.

Next year's LOE at Seneca is expected to be higher than this year's due to increased steaming cost in California. For fiscal 2017 ,we are forecasting steam fuel costs in excess of $5.00 per BOE, up from the $3.20 we've seen over the past year.

This is driven both by higher assumed natural gas prices as well as the fact that Seneca expects to incur significant upfront LOE costs to get steam flood operations up and running on the recently acquired leases John mentioned earlier. Longer term, we expect steam fuel costs trend back to the $4.00 to $5.00 per barrel level, assuming a long-term $3.00 gas price.

The gathering segments earnings and cash flows in 2017 will track the increase in Seneca's gross Marcellus volumes. Recall that while Seneca's net production forecast to be flat year-over-year, volumes attributable to the JDA increased meaningfully.

For fiscal 2017 we expect the Gathering segment's revenue will be between $95 million and $105 million, up from the $90 million area we forecast for fiscal 2016. Giving continued investment, we expect operating and depreciation expenses will increase, relative to their current level but a large portion of the revenue increase should fall to the bottom line.

Turning to the regulated businesses, fiscal 2017 earnings and cash flow in the pipeline and storage segment should be consistent with fiscal 2016 levels. Some of the growth associated with our expansion projects will be offset by an aggregate $6 million reduction in rates that stems from our recent settlement at Empire, and the second phase of the settlement we agreed to last year at Supply Corporation.

Considering those items, we expect pipeline and storage revenue for fiscal 2017 will be relatively flat in the $300 million area. As a result of our recent expansion projects, we expect O&M expense in the segment will increase to about $85 million to $90 million and property tax expense will increase to about $27 million to $30 million.

DD&A expense should be flat as the impact of the expansion projects will be offset by a drop in Empire's depreciation rates as a result of the settlement.

Utility earnings should be relatively flat, compared to fiscal 2016. Assuming normal weather, the Pennsylvania division should see a pickup in margin. Recall that the winter of 2015-2016 was amongst the warmest on record. However, that benefit will be offset by higher depreciation and operating expenses related to our new customer billing system.

Our New York division, which represents about two thirds of our utility operations has a rate case on file with the PSC. Our guidance takes into account new rates going into effect April 1, 2017.

Turning to capital spending, we are reducing our fiscal 2016 guidance to a range of $390 million to $440 million which is roughly a 10% decrease at the midpoint. While spending at the Utility remains in line with our previous guidance we now expect the other segments will come in a near or below the end -- below the low end of prior guidance ranges. The vast majority of this shift is given by the timing of spending between fiscal 2016 and 2017, along with our continued focus on controlling spending.

Looking to fiscal 2017, our initial consolidated CapEx guidance is $725 million to $835 million. As Ron said earlier, we remain on track to begin construction next spring on the Northern Access pipeline. The total cost of that project is expected to be $455 million, of which a little more than $40 million has been spent today.

Approximately $300 million will be spent on the project in fiscal 2017 with the balance in early fiscal 2018. As John previously mentioned, spending levels at Seneca will increase modestly, despite maintaining a one-rig program as drilling shifts from 20% working interest JDA wells to 100% Seneca-owned acreage and Utica appraisal work.

All told from a spending perspective, we remain committed to investing in the safety and reliability of our pipeline system and developing the needed infrastructure to move production in Seneca's acreage to higher value markets in the Northeast and Canada.

From a liquidity standpoint, the extension of Seneca's JDA with IOG further strengthens our balance sheet and we now expect Seneca to generate free cash flow both this year and next. Combining this with the downward revision in capital spending, we anticipate exiting fiscal 2016 with $50 million to $100 million in cash on hand.

Moving to fiscal 2017, we expect capital spending and dividends will exceed cash from operations by approximately $300 million. Most all of this outspend will be driven by the Northern Access project. Outside of our pipeline business all our other segments are expected to generate free cash flow.

In the near term, we expect to meet or outspend with a combination of cash on hand and short-term debt. The bulk of the capital spending on Northern Access will occur next summer so as we move through the fiscal year we will evaluate and ultimately execute longer term financing.

With that I'll close and ask the operator to open the line for questions.

(Operator Instructions). Holly Stewart, Scotia Howard Weil.

Just a couple quick ones. John, your comments on the Utica are pretty exciting. You mentioned as your confidence builds you would maybe move more toward a Utica development versus the Marcellus. So I'm assuming this would be sort of a 2018 kind of timing after this sort of six-well plan that you mentioned.

That's exactly right. We have at least -- we have three wells this year that we will test, in fiscal 2017. And then we will go into fiscal 2018 and it will be another four wells. And at that stage we will be ready to make the decision on whether to move forward with that Utica development program. But that's exactly right. It would be a Fiscal 2018, fiscal 2019 program.

So maybe late 2018 decision then?

Yes.

And then just sort of comparing the CapEx for E&P year-over-year, kind of the delta between the two, I'm assuming that jump up is just due to the Utica testing?

Utica testing, and plus we will be drilling additional wells in Lycoming. We will be moving to Gamble this fall and drilling, I think it's eight wells, for fiscal 2017 in preparation for Atlantic Sunrise.

Okay. And then maybe one, just talk a little bit about sort of the changing dynamics that we can see at Dawn. I know you tied some of your capacity on both Northern Access and Atlantic Sunrise to firm sales agreements. So just sort of on a big picture how you guys are thinking about this, how maybe you could mitigate some of your more mitigation to your exposure, etc.?

We have been paying a lot of attention to it. It's hard to speculate until we understand what volumes we could potentially see heading to Dawn from West Canada. But most of the analysis that we have seen has essentially erased some of the premium to Dawn to NYMEX. But worst-case we've seen is that Dawn approaches NYMEX and those to essentially trade roughly together. We continue -- we continue to convert Dawn Index into NYMEX going forward, we still see a bit of a premium related to that but I can see that flattening out over time as well.

Okay, great. And then maybe a big picture question, if I could, for Ron. Just any new thoughts to share on just the MLP market, and maybe if that sort of moving up on the options for funding in the future?

It remains an option, but there's -- for the IPO market, we just haven't seen that come alive again yet. As Dave mentioned, given our construction program and the need for financing really not occurring until next summer at the earliest. We've got plenty of time that remains to be on the table, but as we move forward, again with the JDA, our capital costs have decreased and our balance sheet is getting stronger.

So it remains an option, but the whole market has to get a little bit better. Let's put it this way. I don't expect that National Fuel would be the first to test the IPO market again.

Fair enough. Thanks guys.

Kevin Smith, Raymond James.

Good morning. John, seems to be some different viewpoints out in the industry about shut in productions in Central and Northeast Marcellus. Maybe from where you sit, is Seneca constrained at all in the Marcellus, and are you seeing a regional production declines which allow you to increase spot sales?

We had a good quarter selling into the spot market. As I said in the release here it's about 6.4 Bcf. We've seen prices fall off recently, we did curtail about 4.5 Bcf for the quarter. If prices stay where they are in the spot market, I see that that would probably increase going into next quarter. It's hard for me to comment on Northeast and Southwest PA. It's very different dynamics, and that's just -- it's difficult for me to comment on that.

Okay. Fair enough. And then Dave, would you mind reminding me, I guess about the next project milestones, what we should be looking for on Northern Access?

Well, we received our EA from FERC, the next thing we'll get out of them will be a certificate in late October or early November, and then the next major milestone will be the water quality certificate out of the New York DEC that we would expect in the first week of March 2017.

Okay, that's all I have. Thanks.

(Operator Instructions). Tim Winter, Gabelli.

Good morning and congrats on the quarter. I wanted to ask about the $300 million shortfall. Looking at the balance sheet, it looks like the impairments are sort of putting a dent in the equity ratio. How do you think about the equity ratio as it relates to the financing and maybe what is the Utility's equity ratio in the rate filing, and does that impact your thinking as well?

From -- when we evaluate our credit, we take an approach that's similar to the way the rating agencies look at us, which is principally a debt to EBITDA or FFO to debt type metric. We are certainly mindful of the capital structure but our principal focus is on the leverage metrics.

From a rate case perspective, the New York Division -- I'm sorry, the New York PUC has pretty much consistently used 48% as an equity component in recent cases, and that's what we've included in our filing. It also is what we had agreed to in our settlement in 2013. So if you look at that 48%, it's about our consolidated level, but it would be below the equity component of our utility on a standalone basis, which would be in -- call it low to mid 50% area.

Okay, thank you.

I'm showing no further questions at this time. I'd like to turn the call back over to Brian Welsch for closing remarks.

Thank you, Jamie. We would like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 3 PM Eastern time on both our website and by telephone and will run through the close of business on Friday, August 12, 2016. To access the replay online, please visit our Investor Relations website at investor.NationalFuelGas.com, to access by telephone, call 1-855-859-2056 and enter the conference ID number 46345887.

This concludes our conference call for today. Thank you and goodbye.

Ladies and gentlemen, thank you for participating in today's conference, this does conclude the program, you may all disconnect. Everyone have a great day.