National Fuel Gas Company (NFG) Q3 2016 Earnings Report, Transcript and Summary

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’d 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 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 third quarter fiscal 2016 earnings release and the February Investor Presentation have been posted on our Investor Relations website. We may refer to these materials during today’s call. We would also 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 two weeks, and the Barclay’s 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 seeing 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 reported 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 that we have going on. I can assure you that, that’s 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 the 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’re well along meeting our targets for our mainline and service renewal program. Both 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 the investments that we’ve 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 request and interrogatories from the Public Service Commission and new rates wouldn’t go into effect until next spring. Our pipeline in 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 1st. 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’re 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’ll 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 was at our dual fueled, provide 57% of the electric power generation capacity in the state. And that natural gas in dual fuel projects make up 65% to 70% of the new generating capacity that is being studied for interconnection to the grid. Clearly, if we’re going to keep the lights on in this day, 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’re 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 point and how the new capacity can be integrated with the existing capacity, that’s some of the shippers already have. We expect that this project will have a fiscal 2019 in-service day 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 or 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’ve 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 PGP receipt points. Although prices have fallen off recently, over the quarter we are 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 Midwest 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 elevate this shortage, we have 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 17 and nearby track we recently formed into. As a result within the next 12 months, we should be able to both increase our daily production at North Midway and have sufficient steam to begin our 17N development. And moving to our Utica Point Pleasant appraisal program, our first Claremont 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 this 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. Partial gradients were high across the Utica target in this area, and therefore we’ve brought this well online slowly with controlled 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 around 1,400 Mcf per 1,000 feet which is about 60% to 70% higher than our typical Claremont Marcellus wells in the same area. Over the first 45 days, this well has produced over a quarter of the 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 no planning on drilling 6 additional Utica wells over the next year, all off our Claremont Marcellus development pads. We have 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’ll be testing it in different completion design. As we move forward with this appraisal program, we’ll be testing different landing zones in some of these well, and we will continue to experiment with our completion design for this area. In addition as we move to the south and southeast across our WDA fee acreage, Utica debts and subsequently pressures could increase significantly. Therefore, if the rock quality remains similar, we think there is a good opportunity to 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 from Marcellus pads that are already built and tied into our midstream infrastructure. Since minimal midstream build out 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 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 low 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 Marcellus joint development program. As a result, IOG has committed to participate in the total of 75 Marcellus wells in the CRB area. We've already drilled 59 of these wells, 39 of which are producing. To-date IOG has invested a total of a $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 '18. The impact of the IOG joint development program reduced activity levels and improved operational efficiencies have led to a substantial decrease in the forecasted spending for both this year and next. For fiscal 2016, we're 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're also tightening our production forecast for this year to now range between a 160 Bcfe to 165 Bcfe. We'll likely end the year with a WDA duck count between 60 to 65 wells ahead of the 2017 Northern Access and service date. For fiscal 2017, we're forecasting capital expenditures to range between $160 million to $200 million, a 125 million to 135 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'll continue with a daylight only WDA frac operation throughout much of the fiscal year. But as start up 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 Bcfe to 175 Bcfe, essentially flat year-over-year. Natural gas production in Pennsylvania is forecast to range between 130 Bcf to 153 Bcf. Absent the IOG joint development agreement total productions would have grown by around 10% year-over-year. A 125 Bcf of forecasted net production has been locked in both physically and financially at an average realized price of approximately $3.5 per Mcf. In addition, we have firm sales for another 12.5 Bcf of net production, and therefore we enter fiscal 2017 confident and our ability to sell almost all of our expected production at attractive pricing. In California we're forecasting production to range between 20 Bcfe 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 and acreage in Midway Sunset. Our LOE on a per unit basis is forecasted to increase next year primarily related to the start-up with steam operations on our recent Midway Sunset farm and acreage. As we grow our production on these properties, this trend should reverse in fiscal year '18. And with that, I’ll turn it over to Dave.

Thanks, John, and good morning everyone. Natural Fuel’s third quarter GAAP earnings were $0.10 a share. When you backup the ceiling test charges and 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 of 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 and 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 oil prices. In addition, the steam operations in North Midway were constrained during the quarter in advance of the new water treatment facility that went into service in late June. Seneca also saw improvement in G&A expense. There were a couple of onetime 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 while 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 stand low to mid $0.70 per Mcfe area given the significant improvement in F&B cost. The second major earnings driver is Appalachian pricing. For much of the quarter, basis was stronger than it has been in recent quarters. This combined with a higher NYMEX price, contributed to our ability to sell the spot volumes John mentioned earlier, which benefitted the earnings of both Seneca and NFG Midstream; however, National Fuel Resources our non-regulated energy marketing company experienced the flipside of the stronger basis as higher than expected purchase gas cost squeezed its gross margin for the quarter. Lastly, our effective income tax rate was unusually high 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 tax rate to move back to the 38% to 40% area. Turning to earnings guidance, we now expect fiscal ’16 earnings will be between $2.90 and $3 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 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. The summary of all of our updated assumptions is continued on page 6 of last night's release. Looking at next year, our preliminary earnings guidance for fiscal ’17 is a range of $2.85 and $3.15 per share. Our guidance assumes a Henry Hub gas price of $3 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're well hedged for fiscal '17 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 Bcfe to 175 Bcfe. This is a somewhat tighter range than in prior years, which reflects the considerable amount of firm sales we've 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's night 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 '17, we're forecasting steam fuel costs in excess of $5 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 cost to trend back to the $4 to $5 per barrel level assuming a long term $3 gas price. The gathering segment earnings and cash flows in '17, we'll track the increase in Seneca's gross Marcellus volumes. Recall that while Seneca's net production is 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 '16. Given 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 regulated businesses, fiscal 2017 earnings and cash flow in the pipeline and storage segment should be consistent with fiscal '16 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 '17 will be relatively flat in the $300 million area. As a result of our recent expansion projects, we expect the O&M expense in this 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 '16. Assuming normal weather, the Pennsylvania division should see a pickup in margin. Recall that the winter of 2015 and '16 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 to effect April 1, 2017. Turning to capital spending, we're reducing our fiscal '16 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 settlements will come in near or below the end -- below the low end of prior guidance ranges. The vast majority of the shift is driven by the timing of spending between fiscal ’16 and ’17 along with our continued focus on controlling spend. Looking to fiscal ’17, 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 ’17 with the balance in early fiscal ’18. 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 standing perspective, we remain committed to investing in the safety and reliability of our pipeline system and developing the needed infrastructure to move production and Seneca’s acreage to higher value markets in the North Eastern Canada. From a liquidity standpoint, the extension at Seneca JDA with IOG further strengthen our balance sheet and we now expect Seneca to generate free cash both this year and next. Combining this with the calendar revision in capital spending, we interstate exiting fiscal ’16 with 50 million to 100 million in cash on hand. Moving to fiscal ’17, we expect capital spending and dividend will exceed cash from operations by approximately 300 million. Most all of this out spend 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.

Thank you. [Operator Instructions] And our first question comes from Holly Stewart with Howard Weil. Your line is now open.

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

That’s exactly right. We have, at least we have 3 wells this year that will test in fiscal ’17, and then we’ll go into fiscal ’18 that will be another 4 wells. And at that stage, we’ll be ready to make a decision whether to move forward with that Utica development program, but that’s exactly right the fiscal ’18, fiscal ’19 program.

Okay, so maybe a late ’18 decision.

Yes.

Okay, and then just sort of comparing the CapEx for E&P year-over-year kind of a delta between the tier and obviously that jump up is just due to the Utica testing?

Utica testing and plus we will be drilling additional wells in Lycoming. We'll be moving to gamble this fall and drill, I think it's eight wells for fiscal '17 in preparation for Atlantic Sunrise.

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 agreement. 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've 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've seen is essentially a raised sum of the premium to dawn to NYMEX. But worst case we've seen is that Dawn [ph] approaches NYMEX and those two essentially trade roughly together. We continue to convert Dawn index into NYMEX's going forward. We still see a bit of a premium related to that but I could see that flattening out over time as well.

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

Well 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's remains to be under 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 the national fuel would be the first to test the IPO market again.

Thank you. And our next question comes from Kevin Smith with Raymond James. Your line is now open.

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 Marcellus, and are you seeing a regional production decline which allows you to increase front sales?

Well, 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 the 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.

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’d expect in the first week of March 2017.

Thank you. And our next question comes from Tim Winter with Gabelli. Your line is now open.

I wanted to ask about the $300 million shortfall and 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 utilities that equity ratio in the rate filing and does that impact your thinking as well?

Yeah, well from a when we evaluate our credit, we’ve taken approach, it's more of the way the agencies look at us which is principally a dent to EBITDA or FFO to debt type metric and 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 am sorry, the New York PUC is pretty much consistently used 48% as an equity component in recent cases and that’s what we’ve included in our filing. It also I what we had agreed to in our settlement in 2013, so if you look at that 48%, it’s above our consolidated levels but it would be below the equity component of our utility on a standalone basis which will be in a low mid-50% area.

And I am 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, I’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 PM Eastern time on both our website and by telephone. And we’ll 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 and to access by telephone call 1855-859-2056 and enter the conference Id no 46345887. This concludes our conference call for today, thank you and good bye.

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.