National Fuel Gas Company (NFG) Q1 2016 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen and welcome to the First Quarter 2016 National Fuel Gas Company Earnings Conference call. My name is Lauren, and I’ll be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] I’d now like to turn the conference over to Brian Welsch, Director of Investor Relations. Please proceed.

Thank you, Lauren 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 Matt Cabell, President of Seneca Resources Corporation. At the end of the prepared remarks, we will open the discussion to questions. The first 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. With that, I’ll turn it over to Ron Tanski.

Thanks Brian. Good morning everyone and thanks for joining our call today. By now most of our shareholders should have received a copy of our Annual Report. As I described in my letter, we’ve structured National Fuel for long-term success. Our recent history has shown our ability to build incremental pipeline projects on a regular basis since 2008. The three pipeline projects that went into full service during the last quarter are the most recent examples. Our engineering and operating folks did a great job on our Westside Expansion and Modernization project, our Tuscarora Lateral project and the Northern Access 2015 project. All came online pretty much on time and we are in full service as of December 1. Our total spending on the projects was just under our anticipated budget of $216.6 million. Our expectation had been to keep that momentum going and get our Northern Access 2016 project built and in service by the end of this calendar year. As we pointed out in last evening's earnings release however, we modified that plan. Given the low near-term commodity prices on the forward strip and even lower spot prices, we’ve decided to lay down another drilling rig next month after it finishes up on its current drill pad. The plan to keep one drilling rig active in order to maintain the drilling efficiencies that we've achieved and to keep our eye on the long-term development plan of our Western development area acreage. For the near-term it’s prudent for us to reduce our capital expenditures and maintain the health of our balance sheet. The IOG joint development agreement helps us do that plus maintain the efficiencies that we've achieved in our drilling operations. Matt will discuss that joint development agreement in his comments. Our decrease in drilling activity will obviously decrease the amount of gas that could flow into the Northern Access pipeline and we’ve move the target completion date of the Northern Access project to November 2017. We knew from the outset of this project that we had an ambitious schedule. Extending the target in-service date gives our project team some more breathing room to complete all the necessary development activities and we will continue to press forward on those. We’ve purchased the compressors for the project and our concluding agreements for the pipe. We are expecting to receive our certificate from the Federal Energy Regulatory Commission or FERC in May and will use the rest of this fiscal year to complete the remaining development activities on the project with most of the construction occurring at fiscal 2017. The revised schedule provides much more flexibility to react to issues that might come up and to plan the construction in an efficient manner. Extending the target completion date and associated capital spending also helps us avoid the choppy waters of the current capital markets. In spite of the current slowdown in our activity, our long-term vision for developing our Pennsylvania, Marcellus and Utica acreage is intact. The Northern Access project is an important part of that plan since the pipeline will be the best outlet to a premium market for production from our acreage. We have a positive outlook for longer-term gas prices and we expect the steep drop in the North American rig count to help bring supply and demand more imbalance over the next year and a half and cause prices in the forward pricing curve to firm up and get us to a point where there is more depth in the financial hedge market that will allow us to hedge our production at attractive prices. Looking farther out past our Northern Access project, the open season that we held for our Empire North project received a strong response and we've got enough requests to fill the approximately 330,000 dekatherms per day of new capacity on that project that has a target completion date in fiscal 2019. We are currently working on proceeding agreements with all of the third-party customers for that capacity. As I’ve mentioned on many previous calls, our project engineers are continually looking at ways to expand our system to move more gas out of the Marcellus and Utica production areas. We have some smaller system expansion and improvement projects on the pipeline systems that we can get done rather quickly under our FERC blanket certificate like our Line D expansion project in Pennsylvania that's designed to add [77,500] dekatherms per day of capacity into our system. There are also at least four more major projects on the drawing board right now and we expect ongoing growth opportunities in this segment of our business. You may have seen in the trade press that our Empire Pipeline was one of four intrastate pipelines where FERC commenced proceedings to review our pipeline transportation rights. FERC had been on somewhat of a regular schedule to initiate rate proceedings for groups of pipelines, but it had gotten out of away from that practice for a while. The rate proceedings are nothing new to us. In fact, we recently settled a rate case for National Fuel Gas Supply Corporation where new rates went into effect on November 1. The current Empire proceeding requires us to make a filing by April 5 and if our rates are changed as a result of the proceeding new rates would go into effect in February of 2017 unless we settle the case earlier. Also earlier this week you may have seen that Standard & Poor's affirmed our BBB bond rating as part of their review of a number of companies in the oil and gas space. While, they did change their outlook from stable to negative they had no problems with our development plans that our team recently laid out for them. One of the aspects of our asset base and business model that we continue to highlight is our ability to modify our development activity depending on market conditions. We always put a lot of information in our releases in quarterly slide decks to help you understand our business so I don't want to take up too much more time here. Each of our business segments remains on a solid footing. Our regulated businesses provide significant downside protection via their stable, predictable cash flows that largely support our debt service and dividend. Combining those businesses with the capital deployment flexibility afforded by our ownership of thousands of acres of drilling rights in Appalachia, plus the operating efficiencies generated by our highly contiguous acreage and our consistent and active hedging program. We believe National Fuel is a solid position even in the current commodity price environment. Before turning the call over to Matt, I would like to comment on some recent changes in management responsibilities at National Fuel. As we announced last month John Pustulka has been named Chief Operating Officer of National Fuel Gas Company and Dave Bauer now has the added responsibility of being the President of National Fuel Gas Supply Corporation, also Carl Carlotti stepped in as President of Distribution Corporation after Anna Marie Cellino’s retirement. As many of you also know Matt Cabell is retiring effective May 1 of this year. Matt has done a great job for us as we transitioned out of our Gulf of Mexico operations and built a team that has made Seneca a top-tier operator in the Marcellus. We will certainly miss Matt, but we are sure that the Seneca team that will be led by John McGinnis will not miss a beat in carrying out our ongoing plans. Now, Matt has an update on Seneca's operations.

Thanks Ron and good morning everyone. As Ron mentioned, we closed the joint development deal on December 2 with IOG Capital. The initial tranche of this deal includes 42 wells that come online over the course of the next six months. IOG will pay 80% of the total cost and will have a 74% net revenue interest. Once IOG achieves a 15% IRR, the majority of their interest will revert back to Seneca. IOG also has an option to participate in an additional 38 wells at terms that are similar, but actually somewhat more favorable to Seneca. Please refer to our December 2 press release or our investor presentation for the details. The most important things to understand about this deal are first, Seneca maintains complete operational control. And second, our capital spending is reduced by approximately $200 million from the first tranche alone. In addition to bringing in a partner, we are also reducing CapEx by dropping to a single rig and slowing our completion schedule. As Ron mentioned, National Fuel has delayed the start-up of the Northern Access project to November 2017 such that our firm transportation capacity fits our new development plan. This new plan reduces Seneca's CapEx guidance for fiscal 2016 to a range of only a $150 million to $200 million. However, the reduced activity will have no significant impact on production in fiscal 2016 and we still anticipate double-digit compound annual production growth over our five-year planning cycle. Despite our reduced drilling activity Seneca will continue to complete wells this fiscal year in order to keep our existing firm transportation capacity full and to be fully prepared for Northern Access in the fall of 2017. Currently, we have an inventory of about 70 wells that are either drilled, but not completed or awaiting on a gathering line. We have 62 wells online at Clermont now and expect to add 100 more by the end of calendar 2017, allowing us to fill the majority of the Northern Access capacity despite the move to a single rig. We have become extremely efficient in our completion activity. On our most recent pad the D08-G pad, we pumped 387 stages in 36 days for an average of 10 3/4 stages per day. That’s a new record for Seneca and possibly for any operator. On average, we pumped 3 million pounds of sand and 65,000 barrels of fluid per day. Our previous record for pad was an average of nine stages per day. This new pad was important to meeting our current firm transportation and firm sales commitments. Specifically, the start-up of the Niagara Expansion project in December added a 158 million cubic feet of firm transportation into Canada allowing us to boost our total Western development area production to 190 million cubic feet per day. On the marketing front, we continue to layer in additional firm sales and hedges to eliminate uncertainty around our total production and the pricing we will receive. While pricing in general was challenging during the last quarter causing us to voluntarily curtail 14.6 Bcf of gas. We took advantage of select opportunities to lock-in additional firm sales. As a result for the remaining nine months of fiscal 2016, we have 89 Bcf of our gas production locked-in both physically and financially at an average price of $3.25 per Mcf, plus another 5 Bcf of firm sales that lock-in our basis differential. These actions in conjunction with our revised operation schedule significantly reduce the amount of fiscal 2016 production exposed to the spot market and voluntary price curtailments. All of which is reflected in our updated production guidance. So, as Ron mentioned and as you may have read in our press release a few weeks ago, I plan to retire from Seneca and National Fuel as of May 1. John McGinnis, who is currently our Chief Operating Officer, will be promoted to President of Seneca. I have known John for over 20 years and I'm very confident in his ability to lead the Company. We regularly update a detailed succession plan and I'm confident that the Seneca organization is in great shape. Our entire management team is experienced, capable and dedicated. With that, I will turn it over to Dave.

Thank you Matt and good morning everyone. As you saw on last night's release, National Fuel reported a net loss for the first quarter of $189 million or $2.23 per share. As expected the continued decline in commodity prices caused Seneca to record a ceiling test impairment charge that amounted to $2.97 per share. On top of that Seneca incurred $0.04 per share of professional fees related to the joint drilling agreement. Excluding those items earnings for the quarter were $0.78 per share down $0.22 from the prior year largely due to lower commodity prices. In particular, crude oil and natural gas prices after hedging were down $18 a barrel and $0.09 per Mcf respectively. On top of that low spot natural gas prices led Seneca to curtail 14.6 Bcf of production, which is about 10 Bcf more than last year. In addition to impacting Seneca those curtailments also affected our gathering segments earnings. Lastly, the weather on our utility service territory was more than 25% warmer over the normal, which impacted the utility and energy marketing segments earnings by about $0.07 per share. On the bright side revenues in our pipeline and storage segment were up 3% over last year thanks to the three projects that went in service during the quarter. Looking forward, our new earnings guidance range for fiscal 2016 is $2.75 to $3 per share excluding ceiling test impairments. At the midpoint this is a slight increase from our previous guidance that’s driven largely by our reduction in our forecast to DD&A rate, which we now expect to be in the $0.90 to a $1 per Mcfe area. We work diligently to create more certainty around our production volumes and realize pricing. As a result, production for the year is now expected to be 150 Bcfe to 180 Bcfe. And there are two things you should take away from this new range. First, it’s considerably tighter than our previous guidance range and second the bottom end is increased by 8%. As in prior quarters, our production guidance reflects the full range of potential outcomes. If we sell a 100% of our expected spot volumes will be at the high-end of the range. If we don’t sell any spot volumes will be at the low-end. Slide 20 of our new IR deck contains a buildup of our production guidance and the associated firm sales and hedging agreements that we have in place. One thing that’s important to note is that our production range is net of the IOG joint development agreement. Seneca's fiscal 2016 production is reduced by about 21 Bcf as a result of that arrangement, but our NFG Midstream subsidiary still gathers the gross production for the joint development wells. With respect to pricing, we are lowering our commodity price assumptions to $2.25 for natural gas and $40 a barrel for oil down from $2.75 and $50. We are well hedged for fiscal 2016 so the impact of the new commodity price assumptions is relatively modest. As Matt said earlier, for the remainder of the fiscal year we’ve locked in 89 Bcf of natural gas production at a price of $3.25 per Mcf, which at the midpoint of our guidance is 78% of our production forecast. On the oil side, we have a little more than 1 million barrels hedged at $88 per barrel, which represents just under 50% of our expected oil production. We continue to actively pursue incremental hedges and firm sales to lock in the economics of our program as we grow into the volumes required to fill the Northern Access and Atlantic Sunrise projects. Our assumptions with respect to Seneca's cash operating costs are unchanged. Seneca's first quarter G&A rate of $0.52 per Mcfe reflects the professional expenses that I mentioned earlier, but our full-year rate is expected to be $0.40 to $0.45 per Mcfe. Outside of the timing of the Northern Access project, our assumptions with respect to the other businesses haven’t changed. As a reminder, our forecast for the utility assumes normal weather. As we saw this past quarter, weather can have a big impact on results. The month of January was about normal, but recent forecast for February and March are a little warmer than normal. Turning to capital spending. As you can see on Page 3 of last night's release, the reduction in Seneca’s activity will have a meaningful impact on our capital spending plans in fiscal 2016. As Matt mentioned earlier, Seneca's updated capital budget is now $150 million to $200 million net of payments from IOG on the first tranche of wells. At this level of spending I expect Seneca will generate positive free cash flow in fiscal 2016. E&P capital maybe reduced by a further $90 million to $100 million if IOG exercises their option on the second tranche of wells. Gathering capital is now expected to be between $85 million and $95 million, which reflect Seneca's reduced level of activity as well as some opportunities that were identified by the Seneca and NFG Midstream teams to further reduce capital spending without impacting the online target dates of Seneca's productions. As a result of the delay in the Northern Access project, the pipeline and storage capital budget is now $125 million to $175 million. That spending will be for several items including the completion of the three projects that went in service in the first quarter. The construction of the $20 million expansion of Line D that will be built this coming summer, some initial spending related to Northern Access and our typical general system maintenance and modernization. In total, our consolidated capital spending for fiscal 2016 is expected to be between $455 million and $575 million, which is about 50% lower than our previous guidance. From a liquidity standpoint, we’re in excellent shape. Given the reduction in capital spending and limited exposure to spot pricing for our production we will not need to access the capital markets in fiscal 2016. In fact, assuming the midpoint of our earnings and capital spending guidance, we expect to end the year with our $1.25 billion credit facilities undrawn and fully available to us. Further, we don't have any long-term debt maturities until 2018. In closing, the benefits of our corporate structure are particularly evident in today's challenging environment. 2016 will be a difficult year for the energy industry, but our balance business model gives us a clear advantage. Our regulated operations, which comprise roughly half of the Company, generate stable and predictable cash flows that largely support our debt and our dividend. At the same time, the integrated nature of our Company, which is underpinned by our large fee acreage position in the Marcellus, allows us to scale up and scale down our development plans as commodity prices dictate. The current market will make the near-term challenging for producers, but we believe that National Fuel is well-positioned financially and geographically to weather these trying times and over the long-term deliver significant value to our shareholders. With that, I'll ask the operator to open the line for questions.

[Operator Instructions] Our first question comes from the line of Kevin Smith with Raymond James. Please proceed.

Hi, good morning gentlemen.

Hi, Kevin.

Hi Kevin.

And Matt, congrats on your upcoming retirement. You'll be missed.

Thank you.

But I wanted to spend some time on the E&P segment. Do you have the breakout of drilling versus completions in this year's capital spending?

Do you have that handy, Dave, by any chance?

Or maybe a percentage, rough?

You know what I think I’ve got if you hang on one second Kevin, I think I can give you a specific number, so for fiscal 2016 we expect to drill 50 wells and complete 36.

Gotcha. And then what's your last rig that you've got, how long is that contracted for?

It goes until late calendar 2016.

Okay, and then one last question for me and I will jump off. Hasn't been a lot of talk about capital spending in California. Is that something that even makes sense at this point in time?

Yes, we have reduced our capital spending in California a bit, but frankly for fiscal 2016 most of the capital has already been spent in California. As we look forward to the next several years, if pricing stays where it is, we will be looking at spending that's say half to two-thirds of what we would have spent otherwise. Most of the things we do out there make economic sense at a price that’s actually lower than $40 a barrel. So they're still our projects that make sense for us to drill even in today's environment.

Okay, that's all I have. Thanks.

Your next question comes from the line of Tim Winter with Gabelli. Please proceed.

Good morning and congratulations Matt.

Thanks Tim.

Matt I wanted to ask two questions about Slide 21. First, do you guys expect Seneca's 2018 production to be at a level that would fill the capacity outlined here? And then secondly, are you able to achieve the production level there and pipeline capacity without accessing the capital markets before 2018?

Why don’t I take the first part of that question and I guess the way I would answer that Tim is to say, well we don't expect to fill every MMBtu of this capacity on day-one. We are going to be fairly close and it will only be a matter of months before we have ramped up to the point of filling all of it.

And then Tim with respect to financing I mean we certainly have a lot of time to decide exactly how we’ll finance the Northern Access project, but at this point when you think of the IOG joint drilling agreement that we had that gives us a huge amount of flexibility and the pullback in Seneca’s capital. We will preserve a lot of capital that as we go into 2018 should give us a lot of room on our credit facilities.

Okay, great. Thank you.

You bet.

Our next question comes from the line of Chris Sighinolfi with Jefferies. Please proceed.

Hi good morning guys.

Hey, Chris.

Hi, Chris.

Hi Chris.

Matt congrats, I hope you get some time to enjoy Michigan a little bit more than you've been now that you'll be retired. So, congrats on that coming up for you. I had a question as you made comments and Dave made comments about the continuation of your practice of seeking to layer in firm sale agreements and hedge positions. And I was just curious how that compared or just dovetailed with Ron what you mentioned about obviously the crash in rig count and your hope that that translates into a stronger price in the future? When you think about your historical practice around financial hedging, are you inclined at all to maybe slow down a bit given the rig activity and given the likelihood that that might translate into better pricing in the future?

Yes, I would say that when you look further out on the curve that’s the case, our hedging policy has a range that we try to target when we look further out and I would say that at this point given were prices are we tended towards the lower end of that range of hedge position. And I’m talking Chris when you go out 2017, 2018 and 2019 and beyond.

Okay.

Yes. Chris, this is Ron. And when you look at say NYMEX futures contracts, you don't see $3 kicking in I mean as of today or yesterday until January of 2018, but even if you are looking to layer in those hedges, the market is so thin out there I mean that there is very few contracts being traded. So that's why the extension or the pushing off our pipeline while drilling and pipeline at least for a year gives the market a chance to get some more depth at least in the financial market for us to be able to layer in those hedges.

Okay, and then as we think about obviously the FT gets pushed along with the project, but I think if memory serves you had some firm sale on the north end of Northern Access 2016, which would have started with the pipe's original schedule. So how should we think – correct me if I'm wrong about that, A, and then B, how do you think about reselling that capacity or what should we anticipate you'd do with it?

Chris, are you referring to the capacity we’ll have in Canada.

Yes. And I thought the goal was on the backend of FT on Northern Access 2016 to enter into firm sale agreements to sort of physically lock-in that from through the stack. So I'm just curious how we think about that.

Yes. So we will have some capacity in Canada that takes it from the border to Dawn that actually has a lot of value. So we believe that we’ll be able to put ourselves on a position that's relatively neutral on that capacity that we won't be using during that one-year delay.

Okay. And I mean right now is that a positive economic value if you were to do that now Matt? I mean or is there a way, I guess better said, is there a way for me or for the general community on the line to track that in any way?

The way I would think about it is it probably has more value in the cost of the capacity. However, we’re not certain that we’ll be able to do a deal on all of it. So net-net we think we’ll be about neutral.

Okay. And then I guess the final question for me is just as we think, maybe Ron this is probably best addressed to you, we've had a lot of deals in this space in the last several months where utility operations were in part a tenant of the acquired firm, but also midstream was also a component. We saw that earlier this week with Questar, we saw Dominion talk a lot about this “hub concept” of the pipe business that led them to be interested in that business. And as we think about your pipeline network across Pennsylvania and New York, the eastern side of the connection into Canada, seems to satisfy that hub concept in similar fashion. I was just curious your thoughts around the marketplace today, if that's been anything that you've been approached with? I don't know what you can disclose to us, but I'm curious just given the overlap of National Fuel's composition relative to what we've seen trade so far in the last six to nine months. Any thoughts from you?

Yes, sure. I mean we’re obviously always aware of what's going on out there with other peers or other people in the space. As we've looked at the Company and you know our story has been relatively consistent over the last number of years about the benefits that we see in our integrated model. That model and the combination of assets that we have is a little bit different than some of the other companies that you’ve seen particularly because of the large acreage position that we have in the Utica and the Marcellus. Our goal and our vision as I mentioned in my prepared remarks is to continue to move forward and develop the thousands of acres that we have. As I pointed out in the annual report, I’ve been in the industry for a lot of time and seen a lot of cycles and we just happen to be at the down point right now and we’re just generally relatively bullish on the whole space. And we think there's going to be a lot more opportunities for us with our current structure.

Okay, thanks very much for the thoughts, guys, and the added color. And again congratulations Matt.

Thanks Chris.

Your next question comes from the line of Holly Stewart with Howard Weil. Please proceed.

Good morning, gentlemen, and also I'd like to extend my congrats to Matt. Matt, I'll miss our Houston updates.

Thanks Holly.

Okay, so just going to bridge the gap a little bit, I mean it's pretty easy to work this stuff through the strategic move through the pipeline business. But Matt on the production side I think it gets a little tougher with the one rig program and then trying to fill Northern Access in 2018. So maybe starting with those numbers that you gave Kevin on the drilled wells and then the DUC numbers that you gave, the DUC numbers sounded like they were as kind of currently or I guess DUCs plus gathering can you give us the estimate for maybe year-end 2016?

Sure. Yes, so let me start with year-end 2015. At year-end 2015, we had 54 DUCs and 30 WOPLs waiting on pipeline. So I mean that’s 84 wells, we’ve completed some of those and that's why I came up with the number of 70 as our current number. At the end of 2016, we anticipate having 65 DUCs and 7 waiting on pipeline. So really not a significant decrease in the total over the course of fiscal year and that's because we’ve already drilled a lot wells with the three rigs we had running for the first quarter.

Okay and then that 42 wells? Sorry, go ahead.

Well, I was just going to say and then we’ll bring that down some by the end of 2017 and then really the big push will be that first quarter of fiscal 2018 as we approach the timing of the pipeline.

Yes, okay. And in the 42 wells under the joint venture agreement that I guess first slug, those have already been drilled I'm assuming?

Yes. The entire first slug has been drilled.

Okay.

Yes, all of these numbers include – these aren’t net numbers, these are 100% well numbers so it includes the entire joint venture wells as well.

Got you. And we had previously having talked about a 70 wells being turned to sales in 2016. Is that still sort of the estimate?

No, I'd say that's a little high now for fiscal 2016. I think what I said was we’d turn another 100 to sales between now and the end of calendar 2017. And I don't know that I can tell you exactly how that spreads between 2016 and 2017.

Okay. And then maybe in the WDA is there just is there a general rule of thumb in terms of one rig running, how many wells that rig can drill?

Yes, I mean it kind of depends, Holly so if we drill a pad with 14 wells and then move to another 14 well pad. We drill a lot more wells than if we’re moving the rig around. So for instance this fall we will move the one rig back to Lycoming County to drill, it's about 10 wells. And that obviously takes a little bit more time, but I think generally we are probably drilling. I don’t know – I’ll tell you what, let me get back to you with a number on that rather than put out an estimate.

Okay, just trying to get a number as we move it through 2017?

Yes, it's on the order of 25 wells.

Okay. Perfect, thanks guys. End of Q&A

I would now like to turn the call over to Brian Welsch for closing remarks.