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National Fuel Gas’ (NFG) CEO Ronald Tanski on Q1 2015 Results – Earnings Call Transcript

National Fuel Gas Co. (NYSE: NFG ) Q1 2015 Earnings Conference Call January 30, 2015, 11:00 AM ET Executives Brian Welsch – Director, Investor Relations Ronald Tanski – President and Chief Executive Officer David Bauer – Treasurer and Principal Financial Officer Matthew Cabell – Senior Vice President Analysts Kevin Smith – Raymond James Carl Kirst – BMO Capital Markets Timm Schneider – Evercore ISI Tim Winter – Gabelli & Company Holly Stewart – Howard Weil Operator Good day, ladies and gentlemen, and welcome to the first quarter 2015 National Fuel Gas Company earnings conference call. My name is Katina, and I’ll be your coordinator for today. [Operator Instructions] I would now like to turn the presentation over to your host for today’s call, Mr. Brian Welsch, Director of Investor Relations. Please proceed. Brian Welsch Thank you, Katina, 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. This morning, we posted a new slide deck to our Investor Relations website. We may refer to it 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. With that, I’ll turn it over to Ron Tanski. Ronald Tanski Thanks, Brian. Good morning, everyone. Well, for the first quarter of our 2015 fiscal year, everything went pretty much according to plan, except for commodity prices. Build activities in all of our operating companies have been generally moving along according to design. In our upstream business, Seneca continues to drill and complete wells. Our midstream companies continue to install gathering lines and plan for large diameter transmissions projects that will provide an outlet for Marcellus production. And despite a like effect snow storm that piled up five to seven feet of snow across a band of our utility service territory over a few days in November, our utility employees have managed to keep the gas flowing to all of our customers. Focusing on our quarterly earnings, there was increased throughput in our gathering business and additional short-term contracts in our gas transmission business that pushed our earnings above last year’s levels. Part of the throughput increase was due to the completion of our Mercer compression project that went into service on November 1 as planned. That project has 105,000 dekatherms a day of throughput for a third-party and should generate annual revenues of $5.3 million. Throughput also increased in our gathering systems, where Seneca’s production increased as more wells along our Trout Run Gathering System were brought online. In our downstream marketing company, lower commodity prices helped National Fuel Resources achieve higher margins during the quarter. On the flipside, there was lower average commodity prices during the quarter that reduced earnings at Seneca. Looking forward to the rest of the fiscal year, because of the lower prices we’re seeing in the forward commodities strips, we’ve lowered our capital spending plans accordingly. Matt and Dave will give a little more color on the revised CapEx budget that we highlighted in the table in last evening’s release. But in a nutshell, we’re reducing our CapEx as a result of the lower expected cash flows for the year. Our basic longer-term plans, however, have not changed. In our midstream business, we continue to move forward with our Northern Access 2016 transmission project. A 350,000 dekatherm per day project, designed to move Marcellus gas to Canada. In our upstream business, Seneca is drilling in our western development area, according to a slightly modified schedule, that is still designed to fill up the Northern Access capacity, when it comes online. Our current plans still have that online date in November 2016. More near-term, we’re expecting to receive certificates from the FERC next month that will allow us to begin winter clearing activities for our West Side Expansion Project, our Tuscarora Lateral Project and our Northern Access 2015 Project. Details for each of these projects have been included each quarter in our online investor slide deck, and there were some CapEx numbers for those projects that were freshened up in this quarter. Those projects combined are expected to add $33 million in annual revenues beginning in November 2015. I have mentioned in previous calls, our views regarding a master limited partnership at National Fuel. Based on our modifications to our CapEx budget for fiscal 2015, it still looks like we’ll need additional external financing for our Northern Access 2016 Project. Assuming that we receive a FERC certificate on schedule that financing would be needed in the first calendar quarter of 2016, and it still looks like the midstream MLP would fit quite well in our overall financing plans. There are some interim steps that will need to be taken such as another application to the FERC to change our C-Corp operating subsidiary to an LLC for tax reasons and the eventual filing of an S1 with the SEC. While there has been some noise in the MLP market over the last few months, we think our assets would still be well-received by MLP investors, but we do have some time to see how the market settles out. After a debt issuance that we expect to do within the next six months, our next major financing will coincide with the receipt of a FERC certificate for the Northern Access Project, and we think that an MLP is a good option for that financing. Now, I’ll turn the call over to Matt to provide Seneca update. Matthew Cabell Thanks, Ron, and good morning, everyone. Seneca had a strong quarter of production growth, despite some price-related curtailments. Production was 48.2 Bcfe, 30% higher than last year’s first quarter. We curtailed over 6 Bcf to low spot pricing in Pennsylvania. In California, production was 890,000 barrels equivalent for the quarter, up 6% versus last year. Given the sharp drop in oil prices, we are now planning on a much reduced capital spending plan for California. Total west division CapEx is now forecast to be $40 million to $50 million, a $35 million cut at the midpoint. Our current plans are focused primarily on maintenance spending and on development drilling at Midway Sunset field, which is economic at today’s oil price. Despite the spending decrease, we expect fiscal ’15 production in California to be flat or up slightly as compared to fiscal ’14. Moving on to our east division. In the Utica Point Pleasant play, we have drilled and completed our track 007, well number 73H, in Tioga County. The well has 4,500 feet of completed lateral length and 30 frac stages. We expect to have a rig and a snubbing unit on location in about two weeks to draw this well and a Marcellus well on the same pad, and should commence flare testing by the end of the month. Also in Tioga County, we brought on a new six-well pad at track 595. One of the six wells was a Geneseo Shale well, which had a 24-hour peak rate of 7.8 million cubic feet per day. You may recall that we tested the Geneseo well last year at track 100 with an IP of 14.1 million cubic feet per day. With these two well tests, we are becoming increasingly confident that we have meaningful Geneseo resource potential across much of our eastern development area. Now however we have all three of our horizontal rigs drilling for Marcellus targets in the greater Clermont area, which covers portions of Elk, McKean and Cameron Counties. To date, we have drilled 61 development wells and completed 33 of them. 19 of these wells are online. We expect to bring on another six-well pad next month and anticipate a total of 35 wells producing by the end of the fiscal year. By November, based upon midstream’s Clermont gathering system construction plan, we should have 60 Clermont area wells producing, with total productive capacity in excess of 250 million cubic feet per day. These new wells will flow through the gathering system into the TGP 300 Clermont interconnect, and utilize Seneca’s 170,000 dekatherms of firm transportation that begins November 1. Across our entire Marcellus development, we now have the capacity to produce at a rate of approximately 540 million cubic feet per day, net after royalty, however, low spot prices have led to significant curtailments. Fiscal year-to-date through January we have curtailed 11 Bcf and we are currently curtailing approximately 200 million cubic feet per day. Given low gas prices and the potential for additional curtailments, we are reducing our east division capital spending by another $65 million. Most of this reduction will come in the form of reduced completion activity and reduced cost per well. For fiscal ’15, we are planning wells, many of our wells, with lateral lengths of 7,000 feet and 190 foot stage spacing at an average cost of approximately $6 million. Based on our results to date, we expect these long lateral wells to have average EURs of approximately 7.8 Bcf, which reduces our breakeven price at Clermont by $0.20 to $2.60 per MMBtu. As we continue with our development, I expect additional cost reductions, EUR increases and efficiency gains, which will allow us to further reduce our breakeven price and increase our returns, as our production grows. We have also revised our fiscal ’15 production guidance to new range of 155 Bcfe to 190 Bcfe. The bottom of this range assumes that we continue to curtail production due to low spot prices and have minimal spot sales for the remainder of the year, while the top end assumes that we sell 35 Bcf into the spot market. Looking beyond fiscal 2015, if low gas prices persist, we will continue our development of the Clermont area with a reduced activity level, utilizing two to three rigs and a single frac crew. Even with this lower activity level, we should fill nearly all of our firm capacity, which rises to approximately 570,000 dekatherms per day in November 2016. Our drilling program at Clermont achieves a 15% rate of return at a realized price of $2.60 per MMBtu. So we anticipate acceptable returns using the current forward curve and our cost of transportation on Northern Access 2016. And with that, I’ll turn it over to Dave. David Bauer Thank you, Matt, and good morning, everyone. Considering the drop in commodity prices, first quarter was a very good start to our fiscal year. Earnings were $1 per share, up $0.03 over last year’s first quarter, largely on the strength of our midstream businesses, where earnings were up a combined $0.09 per share. Excluding the impact of lower oil and gas prices, Seneca had a terrific quarter as well, with production up 30%. As expected, the utilities earnings were down slightly, mostly because of increased operating cost associated with the development of our new customer billing system. Earnings for the quarter were a bit higher than Street estimates, and there were three principal areas that contributed to that outperformance. First, Seneca’s per unit DD&A, LOE and G&A expenses were all either below or towards the low-end of the range of our guidance. Combined, these expense reductions contributed about $0.06 per share to earnings. Second, our FERC-regulated pipeline and storage segment had another terrific quarter, driven mostly by continued high demand for short-term capacity as well as incremental surcharges from shippers using alternate transportation paths on our system. As a result, revenues for the quarter were over $3 million higher than we have planned. Lastly, as Ron indicated, NFR, our non-regulated gas marketing subsidiary, had a really good quarter, with earnings of $0.02 per share higher than we had expected. So all-in-all it was a great quarter. While we’re happy with our results, the drop in commodity prices, in crude oil in particular, will be a significant headwind in the last nine months of the year. Our new earnings guidance range for fiscal ’15 is $2.65 to $2.90 per share, at the midpoint down $0.43 from the previous range. Several factors contributed to this change. First, we’re now assuming NYMEX crude oil prices average $50 per barrel for the remainder of the fiscal year, down $35 from the previous assumption. This was by far of the biggest change in our forecast. It impacted earnings expectations by a little less than $0.30 per share. Looking forward, every $5 change in oil prices will impact earnings by about $0.03 per share. As Matt indicated earlier, we’re now reflecting pricing-related curtailments in our guidance. Seneca’s updated production forecast is now 155 Bcfe to 190 Bcfe, down 27.5 Bcfe at the midpoint. In addition to lowering Seneca’s earnings, this drop in expected production will also impact our gathering segment. Its revenues are now expected to be in a range of $75 million to $95 million. We’re also lowering our NYMEX natural gas price assumption to an average of $3 per Mcf for the remainder of the fiscal year, down $1 from the previous forecast. However, because all of the Seneca’s firm sales have been hedged or substantially all of them have been hedged, this change had minimal impact on our earnings expectations. With respect to Marcellus spot pricing, given the weakness we’ve seen in the market, we’re now assuming Seneca receives between $2 and $2.25 per Mcf for its spot volumes for the remainder of the fiscal year, down $0.50 from the previous range. We curtail production when prices get too low. So this spot prices assumption is only for the volumes that we actually sell into the market. The midpoint of our new production guidance assume we have about 20 Bcf of operated spot sales during the last nine months of the year. Therefore, every $0.10 change in the average spot price will impact earnings by about $0.0150 per share. On a positive note, as I mentioned earlier, Seneca saw improvement in its per unit operating expenses during the quarter, and much of that trend should continue for the last nine months of the year. Better than expected reserve bookings to bind with lower than expected capital costs, they are the results of both our reduced budget and lower expected drilling completion costs, all have had a favorable impact on Seneca’s per unit DD&A rate. As a result, our updated guidance now assume Seneca’s full year DD&A rate will be in the range of $1.65 to $1.75 per Mcfe. We’ve also reduced the absolute level of G&A spend by approximately 5% to $72 million. But given the reduced production forecast, we now expect per unit G&A expense will increase modestly to a range of $0.40 to $0.45 per Mcfe. Similarly, for tweaking our per unit LOE guidance up to a range of $1 to $1.10 per Mcfe, mostly due to a higher relative contribution of west division production, where Seneca’s per unit LOE is higher. However, once Seneca’s east division is able to produce at its full potential, you should see Seneca’s per unit LOE move downward by $0.05 to $0.10. In the pipeline and storage segment, on the strength of an excellence first quarter, we’re upping our expected revenues to a range of $275 million to $285 million. And lastly, with respect to income taxes, we’re forecasting an effective rate for the year that’s in the range of 39% to 40%, which is a little lower than what we’ve guided to in the past. Turning to capital spending, our consolidated capital budget is now $1.0 billion to $1.2 billion at the midpoint, a decrease of a little more than $100 million. As Matt indicated earlier, Seneca’s budget is now $525 million to $575 million, a drop of $100 million from the prior budget. Well, that may sound like a relatively modest cut, remember that we’re good part of the way through the fiscal year. Relative to our previous budget for the last nine months of the year, that $100 million equates to a better than 20% cut in spending. The gathering segment’s budget has been reduced by $25 million to a range of $125 million to $175 million. While some of this drop was related to the reduction in Seneca’s activity, a good portion is attributable to a refinement and the timing of the build out of the Clermont system, in particular the timing with which we had compression. Utility budget is now $115 million to $130 million, up $22.5 million from our previous forecast. Net increase is attributable to an expansion project that will provide service to a power plant, that’s in the process of being converted from coal to natural gas. This is a great project that not only adds to rate base, but also helps improve the reliability of our system in the Dunkirk, New York area. Pipeline and storage budget is unchanged to $225 million to $275 million. With respect to financing needs, our lower commodity price and production expectations will certainly impact cash from operations. The cuts in capital spending should keep our level as outspend fairly consistent with our previous projections. Our prior forecast generated an outspend in fiscal ’15 that’s in the $425 million area. Based on our updated earnings and capital spending forecast, we now expect an outspend that’s modestly higher at a little more than $450 million. Most of that increase is attributable to the Utility’s Dunkirk project. Absent that opportunity, our financing needs really wouldn’t have changed much. We’re planning a long-term debt issuance sometime in the spring or summer. Looking beyond fiscal ’15, maintaining a strong balance sheet and the flexibility to deploy will guide our decision making process. As we move through time, we will continue to revise our spending plans in light of the commodity price environment. From a capital allocation standpoint, development of our upstream and midstream opportunities in the WDA will be our top priority. I don’t expect any significant changes to the amount of capital we allocate to the FERC regulated side of our business. The projects on the drawing board clearly set the path to the continued growth of the company. While it’s likely we’ll have a significant outspend in this segment over the next few years, as Ron indicated earlier, the MLP market is a potential option to help meet any funding shortfalls. At Seneca, our new budget projection outspend in fiscal ’15 in the $75 million to $100 million area. As Matt said earlier, should commodity prices remain weak, it’s possible we’ll further slow the pace of our development in fiscal ’16, which could near or even eliminate our E&P outspend. Nevertheless, even at a reduced program, we’re confident that Seneca can grow production to fill its capacity on the Northern Access 2016 Project, shortly after it’s placed in service. And all the while, while Seneca pretty much lives within cash flows. Lastly at the utility, while we are pleased with opportunities like the Dunkirk expansion, given the maturity of our business, we recognized the projects of that size will be relatively infrequent. Therefore, once that project and our new customer billing system are complete, I expect capital needs in this business will return to historic levels, say, in the $60 million to $65 million area. At that level of spending, the utility should be significantly free cash flow positive. With that, I’ll close and ask the operator to open the line for questions. Question-and-Answer Session Operator [Operator Instructions] Your first question comes from the line of Kevin Smith representing Raymond James. Kevin Smith Matt, I guess my first question, and Dave, you touched on this a little bit as well, but can you talk about maybe the duration of your drilling and completion and service contracts? I’m just trying to gauge your ability to further reduce activity if prices warrant. Matthew Cabell Yes. On the completion side, while we have contract, there is no minimum requirement for our completion activity. On the drilling side, we’ve got three rigs, three horizontal rigs. The first one goes off its current contract about the end of this year. And then after that they’re staggered about six months apart. Kevin Smith So those are going to be under contract all for the full calendar year no matter what really, right? Matthew Cabell That’s correct. Kevin Smith And then how much do you think you’re going to be able to lower service costs over the next six to nine months? And I guess is any of that cost reduction baked into your E&P CapEx forecast? Matthew Cabell It is to some degree, Kevin. Our frac contract is extremely competitive. I don’t anticipate a big change in the cost of our pressure pumping, but there’re numerous other vendors that we are currently negotiating with to reduce our cost. So I’m hesitant to predict a specific number, but we’ve baked in something that’s a little lower than where we are today. Kevin Smith And then one question, just on your utilities and I’ll jump off. But is January’s impact really going to have any sort of movement in your Pennsylvania utility earnings as far as the cold weather that we saw? Ronald Tanski Kevin, I don’t think it will be a huge impact. I mean weather has been cold, but it’s been not that different than normal, and our forecast assumes normal weather. Operator Your next question comes from the line of Carl Kirst representing BMO Capital Markets. Carl Kirst I guess maybe kind of following off of Kevin’s question with costs and potential reduction, and this is really speaking to the dynamic of curtailments. And Matt, I know there’s no bright line, if you will, but we’ve always generally thought of $2 perhaps as the area where curtailments may start. Is that still generally something we should be looking at going forward, or does that number have perhaps a downward bias to it? Matthew Cabell Again, I always hesitate to put a real specific number on it, but you’re in the right ballpark. Carl Kirst Maybe a question, one on Northern Access. Could you all remind me how much of Northern Access is predicated on third-party volumes, and if the low commodity price environment I mean obviously there’s need for more take-away, just given the basis, but I did know producers’ willingness to sign long-term contracts in the current market, if that was shifting conversations at all? Matthew Cabell It’s all Seneca? Carl Kirst All Seneca? David Bauer The current design for there project right now is the 350,000 dekatherm per day and Seneca has signed up for all of that. As you know, we constantly look at opportunities to add more capacity on our system throughout the system and the Northern Access is no exception, but right now the project that we have outlined in the slide deck, again that was refreshed and filed last night, is 350,000 dekatherm for Seneca. Carl Kirst And then last question if I could, and this is just a clarification I guess as we look forward, and this is perhaps internal dynamics here between the midstream, gathering and Seneca. But if the current levels of curtailments, for instance, were to be extended and you all were to come at the lower end of the production guidance range, is the midstream segment, is that being paid on a unit fee basis such that that EBITDA for instance maybe down from first quarter as well or is the midstream, I would assume like Northern Access is more of a take or pay? How should we think about that? Ronald Tanski It’s a per-unit rate, Carl. Operator Your next question comes from the line of Timm Schneider representing Evercore ISI. Timm Schneider I just have one quick question on the timing around the MLP. I know you said there is some new stuff that you guys need in terms of approval and filings. So when do you think you will make a decision by in order to have this structure in place for funding of Northern Access? Ronald Tanski Again, one of the first things to do is to file with FERC in order to change the structure from a C-Corp to an LLC. We’re in the process of drafting those documents now. The next thing is obviously the S1. But again as I said the timing of all this should really coincide with the receipt of the FERC certificate, and we’re talking around January or the first quarter of calendar ’16. Timm Schneider And then the other question I just had, in the West, on your oil production, I mean despite the decline of crude oil prices, the nature of how that stuff is flowing, we shouldn’t really expect a decrease in production there, right? That’s kind of what you guys — or basically flattish? Ronald Tanski Basically flattish, yes. We will drilled fewer wells than we would have which has a minor impact kind of towards the end of the year, but production will be pretty flat. Timm Schneider I mean because that’s prices have come-off that much, do think there’s more willing sellers out there now? And I know you said it’s tough to add acreage, but are you guys seeing anything around your acreage? Matthew Cabell I wouldn’t say that we’ve seen a lot already, Timm, but that make change. One thing to keep in mind, California is primarily controlled by some fairly substantial companies, companies like Chevron, Era, Oxy or I should say, Cal Resources. But we are certainly going to be and look out for good opportunities. Operator Your next question comes from the line of Tim Winter representing Gabelli & Company. Tim Winter I was wondering if you could talk a little bit about your either hedge position or firm sales positions out into ’16 and ’17, and if you had any prices as well? Ronald Tanski Our positions are contained in the new IR deck that that’s out on the web on page, I guess page 29. From a hedge standpoint, I mean we haven’t given our production guidance for ’16 yet, but we’re generally call it in that, call it 35% to 34% range hedge for natural gas for ’16. Tim Winter Is that still in that roughly $3.77 area? Ronald Tanski That fixed price contract does extend through our fiscal ’16. Actually that price extends through the period of which the Atlantic Sunrise project goes in service. Tim Winter And then I was wondering, on the Northern Access 2016, who the ultimate customers are? Is there any work that needs to be done on that end, or is pretty much just Seneca taking the output good enough to get that project going? Ronald Tanski Yes. With respect to Supply Corporation building the project, we’re comfortable with Seneca as the shipper. Operator Your next question comes from the line of Holly Stewart representing Howard Weil. Holly Stewart Just a couple of quick ones here. Can you give us the breakdown between the WDA and EDA production volumes for the quarter? And then maybe while you’re looking for that, just trying to bridge a few gaps here, I’m assuming the revenue decline that we are seeing now in 2015 on the gathering side is related to the EDA system? I’m just trying to bridge the gap between growing production volumes into the Northern Access System, the cut to production in 2015, and then the cut to the gathering revenue assumption. Ronald Tanski Yes. So I don’t know that breakdown precisely off the top of my head. Tim, I don’t know if that’s something we can calculate. David Bauer Yes. I mean, rough order of magnitude, Holly, the EDA would be around 34 Bcf or 35 Bcf. Holly Stewart The EDA, okay. David Bauer And then I was a little confused by the revenue question. Holly Stewart So I think you’ve provided new gathering, let’s see, gathering revenue of $75 million to $95 million and previously it was higher? David Bauer Right. And so that’s just a factor of the midpoint of our production guidance coming down. So if you think of the $75 million would be the level of revenue at the low end of the range of Seneca’s production guidance, the $95 million would be at the high end. Holly Stewart Let me maybe rephrase, and maybe this goes to Matt. Just in terms of the production guidance then, is the impact I’m assuming is related to curtailment, so it’s would be on the EDA system versus the WDA system? Matthew Cabell Actually, Holly, virtually all of our production EDA and WDA flows through gathering that was build by our sister company. So it didn’t really matter where it is, it’s either in the Covington system, the Trout Run system or the Clermont system, they’re all are our Midstream company. Holly Stewart So it’s just lower volume in general? Matthew Cabell Yes, right. Holly Stewart And then I missed part of Carl’s question, Matt, so I think he was trying to get to the curtailments number that was in the guidance, but I didn’t hear it all. So you’ve got 6 Bcf that you curtailed in the fiscal first quarter. The new guidance, the new production guidance, you have a number that you’re assuming within there for total curtailments for the year? Matthew Cabell Yes. Think about it this way, the low end is minimal, pretty close to zero. The high end is we’re going to sell 35 Bcf spot. Holly Stewart Spot right? Matthew Cabell Which would be essentially no curtailments at that high end from today forward. The 6 Bcf is just first quarter. As of today we’ve curtailed about 11 Bcf fiscal year-to-date. For reference, Holly, we sold 12 Bcf with spot in the first quarter. Operator Your next question comes as a follow-up from the line of Timm Schneider representing Evercore ISI. Timm Schneider Just one quick question or follow-up on Northern Access. I notice TransCanada was having this dispute with the NEB? I was just wondering if that’s all figured out with that last stretch of pipe from Chippewa to Don, if you guys have come to an agreement with them? Ronald Tanski Yes. That pretty much all got settled out. All of the customers or all of the TransCanada’s customers agreed to the settlements, so that’s all squared away and we’re set to go with that portion. As you know, we’ve picked up capacity both on TransCanada and on Union to get all the way back to Don. So yes, that’s set. Operator With no further question at this time, I would now like to turn the call back to Mr. Brian Welsch for closing remarks. End of Q&A Brian Welsch Thank you, Katina. 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, February 6, 2015. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com. And to access by telephone, call 1-888-286-8010, and enter passcode 80321376. This concludes our conference call for today. Thank you, and goodbye. Operator Thank you. Ladies and gentlemen thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.

Piedmont Natural Gas’ (PNY) CEO Tom Skains on Q4 2014 Results – Earnings Call Transcript

Piedmont Natural Gas Company Inc. (NYSE: PNY ) Q4 2014 Results Earnings Conference Call January 05, 2015, 10:00 AM ET Executives Nick Giaimo – IR Tom Skains – Chairman, President & Chief Executive Officer Karl Newlin – Senior Vice President and Chief Financial Officer Franklin Yoho – Senior Vice President and Chief Commercial Officer Analysts Chris Turnure – JPMorgan Andy Levi – Avon Capital Advisors Spencer Joyce – Hilliard Lyons Operator Good day, and welcome to the Piedmont Natural Gas Year End 2014 Earnings Call. Today’s conference is being recorded. At this time, I would like to turn the call over to Mr. Nick Giaimo. Please go ahead. Nick Giaimo Thank you, Jamie. Good morning, everyone, and thanks for joining the Piedmont Natural Gas year end 2014 earnings conference call. This call is open to the general public and is being webcast live over the Internet. If you would like to access the webcast of this call or view the slides of the accompanying presentation, please visit our website at PiedmontNG.com and choose the For Investors link. On the right hand side of that page, you will find the appropriate links. On the call today presenting prepared remarks, we have Tom Skains, President, Chairman, and Chief Executive Officer, and Karl Newlin, Senior Vice President and Chief Financial Officer. Other officers of the company are also in attendance to take your questions. Finally, this call may include forward-looking statements, and our actual results may materially differ from those statements. More information about the risks and uncertainties relating to these forward-looking statements may be found in Piedmont’s 2014 Form 10-K, filed on December 23rd with the SEC. And with that, I will turn the call over to Tom. Tom Skains Thanks, Nick, and good morning, everybody. And thank you for joining us for our year end 2014 earnings conference call. I know many of you are just getting back into the office after the holidays, and we really appreciate you taking the time to be with us today. As you know, we filed our 2014 10-K and issued our year end earnings release on December 23. This morning, I am going to talk about our 2014 accomplishments and provide you with a general update on the company. Then I’ll turn it over to Karl to give you a more detailed discussion of our 2014 financial results and our 2015 earnings guidance. Let’s begin on slide 2, since Nick has already covered slide 1. I’m extremely proud of what our team accomplished in 2014. We generated net income of $144 million and diluted earnings per share of $1.84. This was 7% and 3% higher respectively than 2013 results. 2014 was also a good year for customer growth. We added more than 16,000 new customers to our system, the strongest year of customer growth since 2008. We executed our regulatory strategy with general base rate relief in North Carolina and successfully completed the first year of Integrity Management Riders or IMRs in both North Carolina and Tennessee. We also outlined future growth in our joint venture portfolio with the announcement of our 10% equity participation in the Atlantic Coast Pipeline project. As Karl will discuss in a moment, we completed the $515 million utility capital expenditure and joint venture contribution program for 2014. Over half of our 2014 capital spend was dedicated to integrity management. And as I just mentioned, we have IMRs in place to recoup that spend in a more timely and efficient manner. Part of our future capital expenditures will be to continue to serve new natural gas power generation facilities in our region. In June, we announced a new power generation delivery project for Duke Energy to serve their planned W.S. Lee facility in Anderson, South Carolina. During the year, we took advantage of the favorable interest rate environment and issued $250 million of 20 year debt at a coupon rate of 4.1%. And finally, our Board once again demonstrated its confidence in the company’s strategic growth plan by raising our dividend in 2014 for the 36th consecutive year. Slide 3 shows our 2014 net income of $144 million, which was 7% higher than 2013. Higher top line margin growth and increased earnings contributions from joint ventures more than offset increased O&M depreciation and interest expense to support that growth. On slide 4, we highlighted our gross customer additions for the year. As you can see, customer gains of 16,251 in 2014 were 14% better than last year’s growth and produced a gross customer growth rate of 1.6% above our initial forecast for the year. Notably, customer additions in all categories reflect good economic growth across our three state service territory. We expect this momentum to continue, which is why we are again forecasting a growth rate of 1.6% in 2015. Slide 5 is an overview of our constructive regulatory environment. In North Carolina, we settled a general rate case and new rates went into effect in January 2014. The settlement includes a 10% return on equity with a 50.7% equity capital component. We also have implemented an IMR in North Carolina to allow us to earn a recovery of and a return on our system integrity investments outside of general rate cases on an annual basis. Our first annual North Carolina IMR adjustment of $0.8 [ph] million was effective in February 2014. We were granted a similar IMR mechanism in Tennessee with the first annual margin adjustment of $13 million effective in January 2014. Subsequently, we made additional IMR filings in both North Carolina and Tennessee. In North Carolina, we filed for an annual margin adjustment of $26.6 million to be effective February 2015. In Tennessee, we filed for an annual margin adjustment of $6.5 million to be effective January 2015. Both filings are before our state commissions and are pending regulatory approval. In South Carolina, we agreed under our last annual rate stabilization filing to an allowed ROE of 10.2% and to an equity capital component of 55%. The new or proposed rates in all three states are consistent with the margin assumptions we provided when we initiated fiscal year 2015 earnings guidance last November. Moving to slide 6, we show our two in-development joint ventures, Atlantic Coast Pipeline and Constitution Pipeline. We announced Atlantic Coast Pipeline or ACP in September 2014. ACP is an interstate pipeline that will run from West Virginia through Virginia and into eastern North Carolina and will have initial capacity of 1.5 billion cubic feet per day. The total project cost is estimated at $4.5 billion to $5 billion and our ownership percentage is 10%. Our other partners are Dominion Resources, who will construct and operate the pipeline, Duke Energy; and AGL Resources. In addition to our proportional cost of the project, we intend to make a $190 million utility capital investment in order to re-deliver ACP gas supplies to local North Carolina markets. ACP made its FERC pre-filing request in October 2014. Our targeted in-service date for ACP is November 2018. Constitution pipeline is an interstate natural gas pipeline that will connect natural gas supplies and gathering systems in Susquehanna County, Pennsylvania to the Iroquois Gas Transmission and Tennessee gas pipeline systems in New York. Williams is the project operator and is a joint venture partner, along with Cabot and WGL. We owned 24% of the pipeline, which is estimated in total to cost $730 million. We received the FERC 7(c) certificate for Constitution in early December 2014 and later in the month we received a notice of complete application from the New York Department of Environmental Conservation. Our targeted in-service date is late 2015 or 2016. In conclusion, 2014 was a very good year for our company. We invested in and delivered substantial earnings growth for our shareholders, executed our regulatory strategy to achieve a fair return on invested capital and reduce regulatory lag, and pursued both utility and complementary joint venture opportunities. I am extremely proud of our nearly 1,900 dedicated and talented employees and want to thank them all for their good work during the course of the year. And with that, I will turn the call over to our Senior Vice President and Chief Financial Officer, Karl Newlin. Karl Newlin Thank you, Tom, and good morning, everyone. As Tom mentioned, we had a good year in 2014, with net income of $144 million and diluted earnings per share of $1.84. Before we get into the details of the income statement, let me touch on our utility capital expenditures and joint venture contributions found on slide 7. In 2014, we invested $515 million in support of customer growth, system integrity programs, and joint venture opportunities. Capital expenditures related to customer growth and system integrity are shown in the blue and red bars respectively. The purple bar represents contributions made to our joint ventures, which in 2014 included investments for the Constitution Pipeline project. In 2015 and 2016, our forecasted joint venture contributions are for both the Constitution and the Atlantic Coast Pipeline projects. And in 2017, the forecasted contribution is only for the Atlantic Coast Pipeline project. As we noted in the 10-K, the partners of ACP intend to seek project financing for 70% of the construction cost and so the amounts shown here only represent our portion of the remaining 30%. We have added light blue bars in 2016 and 2017, which represent utility CapEx under our Atlantic Coast Pipeline redelivery contracts. These expenditures will be supported by long-term contracts and will not be subject to rate cases for recovery of and on these investments. Of the $190 million in utility capital expenditures we plan to invest associated with the redelivery of ACP volumes to North Carolina markets, $170 million will be supported by such contracts, the majority of which will be invested in 2018. Finally, during the second quarter we announced a new power generation delivery project for Duke Energy to serve the W.S. Lee facility in South Carolina, represented by the green bars, in 2015 and 2016. Our contract with Duke was approved by the Public Service Commission of South Carolina in June and we are targeting a May 2017 in-service state. As you can see, with the utility capital expenditure and joint venture contribution program totaling more than $600 million in 2015, 2016, and 2017, we are continuing to make significant investments in the growth of the company. Moving to slide 8, margin of $690 million in 2014 was 11% higher than in 2013. Nearly half of the increase was from customer growth, the full year impact of new rates for residential and commercial customers in North Carolina and Tennessee, and overall colder weather. The remainder was attributable to increased transportation services under new power generation contracts placed into service and secondary market activity. On the expense side, slide nine, O&M of $271 million was 7% higher than last year, primarily due to colder weather across our service territory. As a result of the colder weather, payroll, bad debt expense and contract labor were higher than both last year and our operating plan expectations. In addition, regulatory expenses increased due to amortization changes under the North Carolina rate case. Slide 10 shows depreciation expense of $119 million and general taxes of $37 million, which were 6% and 8% higher than last year respectively. The increase in depreciation was due to increased planned service and related mostly to power generation projects and investments in system integrity programs. Our general taxes were a result of increases in property and franchise taxes. On slide 11, income from joint ventures was $33 million in 2014, 26% higher than last year. So growth was due to increased contributions from SouthStar, primarily due to the new Illinois customer base, as well as higher customer usage as a result of colder weather. In addition, AFUDC from Constitution Pipeline also added to joint venture contributions. Turning to slide 12, interest expense of $55 million was 119% higher than in 2013. This was the result of lower AFUDC interest income, higher amounts due to customers, and higher long-term debt interest expense from new issuances in both 2013 and 2014. As I mentioned, full year diluted EPS came in at $1.84, which is below our revised 2014 guidance of a top half of $1.80 to $1.90. This was the result of three items that occurred during the fourth quarter. First, last year we filed with the TRA to recover $3.7 million in prior period uncollected gas costs. We ultimately settled with the TRA staff to recover $2 million of those costs and we wrote off the $1.7 million difference. Second, the year end stock price of $38 caused us to accrue additional incentive expense for future equity awards. And finally, AFUDC came in lower than projected for the fourth quarter. Lastly, on slide 13 we’ve outlined the assumptions underlying our 2015 earnings guidance of $1.82 to $1.92 per diluted share that we issued in November 2014 and reaffirmed in our December earnings release. Our margin assumptions include customer growth of approximately 1.6%, the expected impact of Integrity Management Riders in North Carolina and Tennessee, the full year impact of the 2013 North Carolina rate case that went into effect last January, lower wholesale secondary marketing margin due to normal weather, and a reduction in margin in South Carolina under the annual rate stabilization adjustments. We expect O&M to be up less than 2% from 2014 results. We expect to realize increased joint venture contributions due to AFUDC from the Constitution and the Atlantic Coast Pipeline projects and have higher interest expense due primarily to the $250 million in long-term debt we issued last September. The guidance also assumes higher depreciation due to additional planned service and approximately $13 million in utility AFUDC. On the financing side, we plan to issue both new long-term debt and equity in 2015 to maintain our targeted leverage ratio of 50% to 60%. As outlined in our 10-K, we intend to issue up to $170 million through an at the market equity program that will run through fiscal year end 2016. This program will supplement the other equity programs we already have in place. I thank you and we will now turn the call back over to Nick to take any questions. Nick Giaimo Thank you, Karl. Jamie, we are now ready to open the call for questions. Question-and-Answer Session Operator Thank you. [Operator Instructions] And we’ll now take our first question from Chris Turnure with JPMorgan. Please go ahead. Chris Turnure Good morning, guys. Tom Skains Good morning, Turnure… Chris Turnure Happy New Year. Can we get a little bit more color on the CapEx table in terms of JV contributions? Could you give us a breakout of how much is going to Constitution and how much is going to ACP in 2015 through 2016? Karl Newlin Yes. Chris, I don’t have that breakdown right in front of me, but I’ll tell you the bulk of that is going to be for Constitution. Given that they got their 2017 certificate and were waiting on some finalization of approval from New York. I would expect with the turning of dirt and construction beginning most of the expenditures are going to be for Constitution. ACP continues to go through its pre-filing process. And so, again, most of the dollars are going to go towards construction at Constitution. Chris Turnure Okay. And then, you said on the ACP utility CapEx, the balance, what’s not spent in 2016 and 2017, is probably all going to be spent in 2018? Tom Skains Yes, that’s right. So you are alluding to the $190 million of utility CapEx that goes to support three delivery contracts under ACP. That’s correct. And the bulk of that will be spent in 2018. Chris Turnure Okay. And then, is there any extra color that you could give us around the equity issuance that you announced in the 10-K? Will that be sufficient to cover your needs through 2016, at least? Tom Skains We anticipate that it will be sufficient to cover our needs through 2016. The at-the-market, or some people call them a dribble program, allows us that ability to issue into the market over the next two years and to be somewhat opportunistic with the timing and the price at which we issue the shares. In addition, I would remind people that we have a DRIP program, a dividend reinvestment program that adds about $27 million a year in equity as well. So that’s an additional $54 million over the next two years. So between that and the dribble or the at-the-market program, we do think that it’s sufficient. If we were to encounter a need for additional capital expenditures or additional opportunities, we could always avail ourselves of a regular marketed offering on top of that. But currently, the $170 million as outlined in the 10-K we deem to be sufficient. Chris Turnure Okay. And then switching gears to customer growth, it looks like you guys are anticipating a little bit of a higher rate than you originally anticipated last year. So the 2015 number is going to be higher than the original 2014 number. But kind of where is that coming from? Is there any change in the anticipated mix there? And then, specifically on residential conversions, are those people converting from oil or are they converting from some other source? Franklin Yoho Chris, this is Frank Yoho. We, like you said, continue to see pretty strong progress and mostly in the residential new construction market. And we’re seeing that across all three states, very consistent across all three states the growth there. And the big growing area is the residential new construction. Commercial is firming up. It continues to do well. And in the conversion market, you mostly see propane and fuel oil. You may see a little bit of electric here and there, but as the preponderance of it is fuel oil and propane. Chris Turnure Okay, great. That’s helpful. Thanks, guys. Operator We’ll take our next question from Joe Zoe with Avon Capital Advisors. Please go ahead. Andy Levi Hi. It’s Andy Levi. How are you? Tom Skains Good morning. Karl Newlin Good morning, Andy Andy Levi Happy New Year to you guys. Karl Newlin Happy New Year. Andy Levi Just a couple of quick questions. Is there like a weather versus normal for 2014 in earnings per share that you can give us? Karl Newlin It’s Karl. I won’t give an exact earnings per share. But you are right; we had a lot of things that happened because of the weather. So as you look to try and normalize it, I mean, there’s just a few things I would point out. To weather adjust, I don’t [ph] remove the incremental margin results that accrued from the wholesale marketing activity, and to normalize that, if you look just at our secondary market activity over and above the results from 2013, I would say those resulted from the weather. And also normalize SouthStar for weather, so to remove kind of the margin component of it. On the expense side, we had some higher O&M that would not have occurred without the weather, namely, over time, some higher bad debt accruals and specific contract labor in our call centers, as well as the incentive compensation accruals. And again, for normalization, I think you can look at prior year results for that. And then, in addition, we also had some one-time items on the expense side that affected the results that should not recur. We had a $2 million write-off of an investment we held at cost and then we also took the $1.7 million write-off for prior-year deferred gas costs in Tennessee that I mentioned in the prepared results. So netting all that out, removing some of the margin, adjusting the expenses, and adding back the one-time items, I would point back to our original earnings per share guidance range in 2014 of $1.73 to $1.83, again in 2014, and I think our results would have come in probably somewhere in the upper half of that range. Andy Levi Got it, okay. And then – so the $2 million and the $1.7 million, if you kind of strip that out, right, because you said that’s kind of one time, and then… Karl Newlin Yes, add it back. Andy Levi Right, right, and then you had higher – so that would be not including the $1.73 to $1.83, obviously. And then, O&M less the weather or whatever it is, I guess what you are saying is go to like the midpoint of the range or something like that and that would kind of give us our weather effect? Tom Skains Yes. I mean, our – at the time when we gave guidance for 2014, we gave a 3% increase in O&M. So that was our expectations going in. So you could take the 2012 number, add the 3% growth, and that would be kind of your normalized O&M for normal weather. Andy Levi Okay. And then on SouthStar, just remind me because I don’t know the answer. I probably should. But they don’t have any – there’s no volatility relative to commodity prices, right? It’s all just purely volume that you would benefit or not benefit from? Tom Skains Yes. They definitely benefit from colder weather. They can be exposed to the commodity, but they do a very nice job of locking in the contracts and trying to hedge against the weather as well. It’s mainly – it is, it’s a retail customer business and they would benefit from additional cold weather usage, as well as additional customer count. Andy Levi And they only deal in natural gas, right, not in any other… Tom Skains That’s correct. It’s only natural gas, and retail marketing. Andy Levi And how much – do you know how much was the incremental bad debt expense for 2014? I mean, I know that it was kind of part of the stuff that you were talking about as the pluses and minuses, but just on the bad debt, do you know how much – relative to normal, I guess? Karl Newlin It was about $2 million, and that’s pretty common for when you have a period of… Andy Levi Yes. Karl Newlin Colder than expected weather. Andy Levi Okay. And then the last question, just around the equity, is the $54 million which is your, I don’t know, DRIP or ESOP or your plans, whatever, is that a part of the 170 or is that incremental to the 170? Karl Newlin Incremental. Andy Levi And you don’t give a share count or anything, like what the average share count should be for… Tom Skains No, we don’t. But we give guidance on a diluted EPS range. So hopefully between our share count today, kind of the numbers we’ve been talking about and the equity issuance, you can back into what you think a fully diluted share count would be. Andy Levi And beyond the blackout periods for the dribble, which I guess are probably around earnings and things like that, are there any type of – like on a stock buyback, there’s a percent of the volume that you can do on a daily basis. Is there anything like that on the dribble? Karl Newlin Yes. There’s a number of limitations on an at-the-market program. You mentioned the blackout dates; as well, there’s volume considerations around it, so. Andy Levi Do you know what those volume considerations are? Karl Newlin I do not know what those are. But, again, we anticipate the $170 million to be adequate for what we’re looking to do over the next two years. Andy Levi Okay. And I guess, that we should kind of – just kind of evenly kind of spread it out, or do you think it’s more weighted towards 2015, the 170… Karl Newlin One of the nice advantages of that program is we can be opportunistic in the marketplace over the next couple of years with it. But from a modeling standpoint, I think it’s safe to assume you just take that and divide it by two. Andy Levi Got it. Okay. Thank you very, very much. Karl Newlin Sure. Operator [Operator Instructions] And we’ll take our next question from Spencer Joyce with Hilliard Lyons. Please go ahead. Spencer Joyce How are you guys? Happy New Year. Karl Newlin Happy New Year. Tom Skains Hi, Spencer. How are you? Spencer Joyce All right, doing well. Thanks for asking. Perhaps, Karl, just a quick one here. I wanted to go back to slide 6 where you all outlined the $26.6 million ask on the North Carolina IMR. And I know it’s tough to kind of project forward your regulatory proceedings. But just based on where the system integrity CapEx budget is, particularly for this year, I would assume our filing at this point next year would be somewhere similar to that number. Is that a pretty fair general assessment? Karl Newlin I think that’s a fair assessment. Spencer Joyce Okay. And then, perhaps secondarily, I’ve noticed a general upward trend in the utility CapEx budget just here over the past few quarters. Have you seen perhaps a more robust organic outlook for the utility, or is that really more of a natural function of just being a little closer to the timing of this trend and having a little better handle on where you may want to put some capital dollars? Tom Skains Yes. Well, two answers to that. I mean, as with any projections, you are closer to the actual spend date; your estimates are going to be more accurate. So you are right. As you look kind of two, three, four years out, the numbers are going to shift around a little bit just because it’s difficult to predict further into the future. And secondly, the increase in the utility CapEx is really driven around the two things that are highlighted in the two bars. I mean, it’s one; Frank Yoho outlined the customer growth expectations that we have. And as you have more customer growth, you necessarily will have more capital expenditures for the customer growth side. And on the system integrity, we continue to have a robust program to invest in the security and safety of our system, and that program continues. So I think you are seeing just those two trends continue in our CapEx projections. Spencer Joyce Fantastic. Thanks for the color. Karl Newlin Yes. Spencer Joyce That’s all I had. Nice year. Tom Skains Thank you. Operator And there are no further questions in queue at this time. I’d like to turn the conference back to our presenters for any additional or closing remarks. End of Q&A Nick Giaimo Thank you, Jamie. This concludes our year end 2014 earnings conference call. Thank you all for joining us this morning. Operator And that does conclude today’s conference. Thank you for your participation.