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.