National Fuel Gas Company (NFG) Q1 2015 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the First Quarter 2015 National Fuel Gas Company Earnings Conference Call. My name is Katena, and I will be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. 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.

Thank you, Katena, 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 today 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.

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 transmission projects that will provide an outlet for Marcellus production. And despite a like effect snow storm that piled up 5 to 7 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 decatherms 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 the National Fuel Resources achieve higher margins during the quarter. On the flip side, it was lower average commodity prices during the quarter that reduced earnings at Seneca. Looking forward through the rest of the fiscal year, because of the lower prices we're seeing in the forward commodity 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 decatherm-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 FERC 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's 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've 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, debt financing would be needed in the first calendar quarter of 2016. And it still looks like a 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 S-1 with the SEC. While there's 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 6 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 a Seneca update.

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 due 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 Tract 007 well #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 2 weeks to draw out 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 6-well pad at Tract 595. One of the 6 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 a Geneseo well last year at Tract 100 with an IP of 14.1 million cubic feet per day. With these 2 well tests, we are becoming increasingly confident that we have meaningful Geneseo resource potential across much of our Eastern Development Area. For now, however, we have all 3 of our horizontal rigs drilling from 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 6-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 decatherms of firm transportation that begins November 1. Across our entire Marcellus development, we now have the capacity to produce [ph] 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've 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're 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 the 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've also revised our fiscal '15 production guidance to a new range of 155 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 2 to 3 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 decatherms 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 return using the current forward curve in our cost of transportation on Northern Access 2016. And with that, I'll turn it over to Dave.

Thank you, Matt, and good morning, everyone. Considering the drop in commodity prices, the 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 costs associated with the development of our new customer billing system. Earnings for the quarter were a bit higher than street estimates, and there were 3 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 had planned. Lastly, as Ron indicated, NFR, our nonregulated gas marketing subsidiary, had a really good quarter, with earnings a couple of cents per share higher than we had expected. So, all in all, it was a great quarter. While we're very happy with our results, the drop in commodity prices and crude oil, in particular, will be a significant headwind in the last 9 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 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 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 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 assumes we have about 20 Bcf of operated spot sales during the last 9 months of the year. Therefore, every $0.10 change in the average spot price will impact earnings by about $0.015 per share. On a positive note, as I mentioned earlier, Seneca saw improvement in its pre-ended operating expenses during the quarter, and much of that trend should continue into the last 9 months of the year. Better-than-expected reserve bookings, combined with lower-than-expected capital costs, that are the result of both our reduced budget and lower expected drilling and completion costs, all have had a favorable impact on Seneca's per unit DD&A rate. As a result, our updated guidance now assumes 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, we're 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, when Seneca's East Division is able to produce at its full potential, you should see Seneca's per unit LOE moved downward by $0.05 to $0.10. In the Pipeline and Storage segment, on the strength of an excellent first quarter, we're upping our expected revenue 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. While that may sound like a relatively modest cut, remember that we're a good part of the way through the fiscal year, relative to the -- our previous budget for the last 9 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 our refinement and the timing of the build-out of the Clermont system, in particular, the timing with which we add compression. Utility budget is now $115 million to $130 million, up $22.5 million from our previous forecast. That 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 at $225 million to $275 million. With respect to financing needs, our lowered commodity price and production expectations will certainly impact cash from operations. The cuts in capital spending should keep our level of 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 capital 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 for 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 narrow or even eliminate our E&P outspend. Nevertheless, even at a reduced program, we're confident 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're pleased with opportunities like the Dunkirk expansion, given the maturity of our business, we recognize 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.

[Operator Instructions] Your first question comes from the line of Kevin Smith representing Raymond James.

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. Just trying to gauge your ability to further reduce activity, if prices warrant.

Yes, Sure. On the completion side, while we have a contract, there's no minimum requirement for our completion activity. On the drilling side, we've got 3 rigs, 3 horizontal rigs. The first one goes off its current contract about the end of this year. And then after that, they are staggered about 6 months apart.

Okay. So those are going to be under contract all for the full calendar year, no matter what, really, right?

That's correct.

Okay, fair enough. And then how much do you think you're going to be able to lower service costs in the next 6 to 9 months and I guess -- is any of that cost reduction baked into your E&P CapEx forecast?

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 are numerous other vendors that we are currently negotiating with to reduce our costs. So I am hesitant to predict a specific number, but we've baked in something that's a little lower than where we are today.

Got you. 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?

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.

Your next question comes from the line of Carl Kirst representing BMO Capital Markets.

I just -- maybe kind of following off of Kevin's question with cost and potential reduction. 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 is 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?

Yes, Carl, again, I always hesitate to put a real specific number on it, but you're in the right ballpark.

Okay. 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 takeaway just given the basis, but I didn't know producers' willingness to sign long-term contracts in the current market if that were shifting conversations at all?

Well, Seneca.

Yes, Carl, the current design for that project right now is the 350,000 decatherms 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 for Seneca.

Great. 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 there are -- 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 feet basis such that, that EBITDA, for instance, may be 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?

It's a per unit rate, Carl.

[Operator Instructions] Your next question comes from the line of Timm Schneider representing Evercore ISI.

I just have one quick question on the timing around the MLP. I know you said some there's 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 the funding of Northern Access?

Well, okay, again, the first thing -- 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. That -- we're in the process of drafting those documents now. The next thing is obviously the S-1. 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.

Okay, got it. 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 are -- basically flattish?

Basically flattish, yes. We will drill fewer wells than we would have, which has a minor impact kind of toward the end of the year, but production will be pretty flat.

I mean, because prices have come off that much, do you think there's more willing sellers out there now? Even -- and I know you said it's tough to add acreage, but are you guys seeing anything around your acreage?

I wouldn't say that we've seen a lot already, Timm, but that may 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're certainly going to be on the lookout for good opportunities.

Your next question comes from the line of Tim Winter representing Gabelli Company.

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.

Sure, Tim. The -- our positions are contained in our -- the new IR deck that's out on the web. On Page, well, I guess, Page 29. We're -- from a hedge standpoint we're -- I mean, we haven't given our production guidance for '16 yet, but we're generally called in that, call it, 35% to 45% range hedged for natural gas for '16.

Is that still in that roughly 377 area? Or...

The 377 -- that fixed price contract does extent through our fiscal '16. Actually, that price goes -- extends through the period at which the Atlantic Sunrise project goes in service.

Okay, okay. And then I was wondering on the Northern Access 16 if -- who the ultimate customers are? Is there any work that needs to be done on that end? Or it's pretty much just Seneca taking the output good enough to get that project going?

Oh, with respect to the supply?

Output, yes.

With respect to the Supply Corporation building the project, we're comfortable with Seneca as the shipper.

Your next question comes from the line of Holly Stewart representing Howard Weil.

Just a couple of quick ones here. Can you give us the breakdown between the WDD -- WDA and EDA production volumes for the quarter? And then maybe, while you you're looking for that, just trying to bridge a few gaps here. I'm assuming the revenue decline that we're 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.

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?

Yes, I mean, rough order magnitude, Holly, the EDA would be around 3 -- 34 to 35 Bcf.

The EDA? Okay.

Yes. And then I was a little confused by your -- the revenue question.

So I think you provided new Gathering, let's see, Gathering revenue of $75 million to $90 million. And previously, it was higher.

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.

Okay, we'll 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 the curtailments. So it's on -- would be on the EDA system versus the WDA system?

Actually, Holly, virtually all of our production, EDA and WDA, flows through Gathering that was built by our sister company. So it doesn't really matter where it is. It's either the Covington system, the Trout Run system or the Clermont system. They are all our Midstream company.

Okay. So it's just lower volume in general?

Yes.

Okay. And then I missed part of Carl's question, Matt. 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, do you have a number that you're assuming within there for total curtailments for the year?

Yes, think about it this way. The low end is minimal, pretty close to 0. The high end is we're going to sell 35 Bcf, spot.

Spot, right.

Right. So -- 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 year-to-date -- fiscal year-to-date. For reference, Holly, we sold 12 Bcf with spot in the first quarter.

Your next question comes as a follow-up from the line of Timm Schneider representing Evercore ISI.

Just one quick question or follow-up on Northern Access. I noticed TransCanada was having a steep dispute with NEV. I was just wondering if that's all figured out with that last stretch of pipe from Chippawa to Dawn. If you guys have come to an agreement with them?

Yes, that pretty much all got all settled out. All of the customers -- or yes, all of the TransCanada's customers agreed to the settlement. 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 Dawn. So, yes, that's set.

With no further questions at this time, I would now like to turn the call back to Mr. Brian Welsch for closing remarks.

Thank you, Katena. 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.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.