National Fuel Gas Company (NFG) Q1 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the First Quarter 2014 National Fuel Gas Company Earnings Conference Call. My name is Philip, and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn over the conference over to your host for today, Mr. Tim Silverstein, Director of Investor Relations. Please proceed, sir.

Thank you, Philip, 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, we will begin with Ron Tanski.

Well, thanks, Tim, and good morning, everyone. Well, we started our fiscal 2014 with an excellent first quarter. Aside from a few items that Dave Bauer will give us more details about later in the call, the quarter was generally in line with our internal expectations. All of our operating segments are performing pretty much as we laid out during our Analyst Day in November. Operations at Seneca are going extremely well. Efficiencies across the entire operation are increasing, as evidenced by continued decreases in both well completion costs and in Seneca's lifting costs. Matt will cover more of the operational details for this segment in his comments. Major issues that we have to deal with in this segment are commodity pricing and basis differentials. Now you've all seen the recent volatility in daily spot pricing brought about by some of the recent winter storms. However, the forward Nymex strip prices for natural gas in 2015 and 2016 have barely moved and are still hovering around $4 per MMBtu. In addition, the basis numbers that we've seen in Appalachia are generally anywhere from minus $0.85 to minus $1.85. Matt has some comments about our plans to deal with those basis issues, but with what we're seeing in the forward market, it's likely that will keep our rig count in Pennsylvania constant through this fiscal year. Even with the steady rig count, because of the efficiencies that we've been able to achieve, we are affirming our production guidance for fiscal 2014. And the midpoint of that guidance reflects a 28% increase over fiscal 2013 production. Weather in our utility service territory during the first quarter was only a few percent colder than normal but more than 11% colder than the previous year. That cold weather increased throughput on our utility system by approximately 11% or 4 billion cubic feet and got us back to sales levels that we last saw in 2006. With respect to our regulated pipeline systems, the cold weather, combined with the increased capacity added by last year's pipeline projects, increased throughput in those systems by 55% or 68 billion cubic feet. As we pointed out many times with respect to the Pipeline and Storage segment, it's not the actual throughput that drives revenues but the demand charges that our shippers pay under our straight fixed variable rate tariff that are important to our revenues and earnings in the segment. With the first quarter's weather returning to a more normal degree day pattern, we've seen all of our pipeline customers fully utilizing their firm capacity contracts, and it points out the prudence of our pipeline customers in maintaining that capacity, under firm contracts, to be able to support their operations. We reviewed a number of new pipeline capacity expansion projects at our last Analyst Day. And we've included that summary again in the updated slide deck that we put up on our webpage this morning. I'm happy to say that each of those projects is moving along according to schedule and we continue to examine additional projects to move Appalachian production to market. A large portion of our midstream spending will be in projects for Seneca, particularly the buildout of our Clermont Gathering System. And we've also got those plans laid out in our slide deck, and we'll have ongoing construction activities in 2014 and 2015, and we'll try to assure that we have the pipeline capacity to move Seneca's WDA production to market as it develops each new well pad in the WDA. I'll point out a refinement to one of our pipeline projects in our revised slide deck. As we look at moving Seneca's production out of the Clermont area, we were able to change the design of one of the projects to move more gas across the national fuel system and deliver the gas to Canada at Chippawa. In the slide deck on Page 49, you'll see that we've increased capacity on the Clermont to Chippawa project by 100 million cubic feet and also bumped up our spending for that project by $110 million. Though we've gotten off to a strong start and we really don't see anything that should prevent us from reaching all the targets that we set out at our Analyst Day, most importantly, we think our integrated model is working very well. The operations across our regulated systems are running safely and efficiently and the utility customers are paying rates that are among the lowest in each state. And between the Gathering and Pipeline segments, we've got the ability to assure Seneca can get its wells online and that its production is delivered to market on a timely basis. I'll turn the call over to Matt so he can cover Seneca's operations.

Thanks, Ron, and good morning, everyone. Seneca had another good quarter. Production for the quarter was 37.1 Bcfe or 51% higher than last year's first quarter. In California, production was up slightly and we are expecting a further increase in the current quarter as the CESP pipeline issue has been resolved. CESP production is now up to 1,400 barrels of oil equivalent per day as compared to 1,100 2 months ago. At South Lost Hills, we are drilling our second fiscal '14 horizontal Monterey Shale well. Both of these 2 wells will be frac-ed and tested in the third quarter. We also have drilling planned at CESP, South Midway Sunset and East Coalinga fields. For the fiscal year, we expect California production to grow by about 5% versus fiscal '13. In Kansas, we've completed our first horizontal well and are drilling our second. The first well is testing and the second will be frac-ed next month. We should have production rates and EUR estimates by next earnings call. In the East division, production was up 64% in the first quarter, as we brought on additional Tract 100 wells. Another Tract 100 pad came on just a few weeks ago and our total Marcellus net production is now over 350 million cubic feet per day. The 6 new wells at Pad N came on at an average 24-hour peak rate of 15.6 million cubic feet per day, 5 of these wells were completed in the Marcellus and one in the Upper Devonian Geneseo Shale. The Geneseo well looks like a good well, but as expected, it is not as good as the Marcellus due to lower reservoir pressure and less gas in place. When we have a bit more production history, we will disclose IP rate, 30 day rate and EUR. It is also worth noting the average cost of drilling to complete the 6 Pad N wells with an average of 32 frac stages was about $6.9 million. We remain focused on both cost reduction efforts and operational improvements and these wells are in line with our goal of reducing Tract 100 drilling and completion costs by 15% to 20% versus fiscal 2013. In our Clermont area, we have finished the drilling of the first 9-well development pad and we are drilling the fourth of 6 wells on the second pad. All 15 of these wells are scheduled to be completed this spring and summer, and online by the end of the fiscal year. The second of our 3 horizontal rigs is just finishing up a pad on Tract 100 before moving to Tract 595 in Tioga County and the third rig is drilling a delineation well in our Sulger Farm area. We expect to drill 4 to 5 Marcellus delineation wells this year and one Utica delineation well. Looking at production for the remainder of fiscal '14, we are anticipating production to be up a little in the second quarter due to Pad N and then relatively flat for the third quarter with only one new pad coming on. In the fourth quarter, we will bring on the 10-well Pad T at Tract 100 and the aforementioned 16 wells at Clermont. Marcellus production alone should exceed half a Bcf a day sometime in the fourth quarter and company-wide production should average over half a Bcf a day for the fourth quarter, barring any significant price-related curtailments. As I'm sure you're all aware, a big challenge for Marcellus producers lately has been volatile basis differentials due to limited pipeline capacity. To address this issue, Seneca has been securing long-term transportation into multiple markets. As was announced in December, Seneca secured 158,000 dekatherms of firm transportation capacity on the Niagara Expansion project, which will deliver our production into Canada beginning in November 2015. In addition, we were recently awarded 189,000 dekatherms on Transco's Atlantic Sunrise project, which will transport gas from Lycoming County to favorably priced markets along the Atlantic Coast. Other firm transportation agreements are under discussion. Let me conclude by saying that we're on track for another year of significant production growth and expect continued growth next year. Looking further out, we have developed a coordinated Marcellus growth plan that includes double-digit production growth matched to firm transportation. Including the 2 projects I mentioned, we have already secured over 350,000 dekatherms of long-term takeaway capacity into multiple markets and plan to add to that capacity opportunistically. While it's difficult to predict short-term basis differentials in Pennsylvania, our long-term plans are secure, predictable and low-risk. Now, I'll turn it over to Dave.

Thanks, Matt, and good morning, everyone. As Ron said, the first quarter was a great start to the fiscal year. Our $0.97 of earnings were up $0.16 per share or 20% over last year's quarter, with all segments contributing to our improved results. Earnings for the quarter also exceeded our internal forecast and there were 3 somewhat unusual items that contributed to that outperformance. First, at the Utility, we recorded a $2.3 million out of period regulatory adjustment. Second, at Seneca, we booked a $1.9 million mark-to-market gain related to the ineffective portion of our crude oil hedges. And lastly, at National Fuel Resources, our non-regulated energy marketing subsidiary, we had a change in the way we recorded revenue. Previously, NFR's revenues were recorded on a 1-month lag. But this quarter, as a result of a recommendation from our auditors, we began recording an accrual for unbilled revenue. As a result, NFR's first quarter includes an extra month of margin or about $1.9 million. While none of these items is significant individually, they all go in the same direction and in aggregate contributed nearly $0.05 per share to earnings. The remainder of our outperformance is attributable to our midstream businesses, which had a very strong quarter. In particular, as Ron mentioned earlier, our regulated pipelines have seeing terrific demand for capacity from both producers and for marketers that are responding to colder weather and available basis spreads In addition to the larger projects we've built, our marketing team has done a great job selling every last bit of available space on our system. As a result, revenues for the quarters were a couple million dollars higher than we had planned and we expect this trend will continue into the second quarter. For the full fiscal year, we expect Pipeline and Storage revenues will be in the range of $270 million to $275 million, which at the midpoint, is a modest increase from fiscal '13. At Seneca, per unit expenses were a little lower than expected but significantly below last year's level. In fact, on a per unit basis, combined DD&A, LOE and G&A were $0.48 per Mcfe or 13% lower than the first quarter of fiscal '13. The quarterly DD&A rate benefited from higher than expected reserve bookings, which were mostly the result of the acreage we acquired in the Gamble prospect area in Lycoming County. Going forward, we now expect our DD&A expense will be in the range of $1.90 to $2 per Mcfe. Per unit LOE was a bit lower than the midpoint of our guidance, but remember there can be some variations in this item from quarter to quarter. The benefit of lower expenses was largely offset by weaker-than-expected natural gas pricing. Before hedging, realized natural gas prices were below forecast, mostly due to lower NYMEX prices. Our forecast assumed a $4 NYMEX price, but the NYMEX monthly contract settlements, which are used to price much of our firm's sales, averaged $3.61 for the quarter. As you can see from last night's release, the weather in our service territory was significantly colder than last year, and January's been even colder. While that had a big impact on our system throughput, the effect on earnings was relatively modest. As Ron said earlier, our FERC-regulated pipeline subsidiaries employ a straight fixed variable rate design, whereby, substantially, all of the cost of service is recovered via fixed demand charges. At the Utility, the New York division's rates include a weather normalization clause, which insulates our margins from swings in weather. We do benefit from colder weather on our Pennsylvania service territory, but at only 1/3 of our customer base the impact can be pretty small. Utility's first quarter results reflect the impact of a new rate agreement in New York. The joint proposal is retroactive to October 1, 2013. And while it hasn't been formally approved by the commission, it's largely unopposed by the parties that precede it. Therefore, we are accounting for it as of that day. The major financial terms of the agreement, which contains a 2-year stay out provision are as follows: first, we agreed to accrue $7.5 million to settle all allegations concerning past earnings, including both the temporary rate proceeding and the Section 66(20) retroactive proceedings. As you recall, we booked an expense equal to that amount last fiscal year, so this provision of the settlement had no impact on results for the quarter. Second, while customer rates are unchanged, we agreed to record additional pension and post-retirement benefit expense and begin amortizing certain regulatory efforts, which explains much of the jump in the Utility's O&M expense for the quarter. On an annual basis, we expect O&M expense will increase by $8.5 million because of these items. Third, the joint proposal targets an incremental $8.2 million of capital spending per year to replace pipeline on our system. And lastly, the revenue requirement under the settlement was set based on an ROE of 9.1% and an equity ratio of 48%. To the extent we achieve earnings that are above that level, the settlement contains an earnings sharing mechanism, which is a common feature in New York rate plans, whereby, our customers receive the benefit of 50% of any earnings above 9.5% and 80% of any earnings above 10.5%. There are additional non-financial provisions in the settlement related to safety standards, service quality and other items, and I won't review those here. If you're interested, you can get a copy of the term sheet from the commission's website. Switching to earnings guidance, we are narrowing our fiscal 2014 earnings expectations to a range of $3.20 to $3.40 per share, at the midpoint, a $0.05 per share increase. In addition to our strong results for the quarter, and the items I mentioned earlier, the new range reflects an update to certain pricing assumptions at Seneca. During the first quarter, we executed approximately 15.5 Bcf of firm sales agreements for the summer of 2014. Considering those firm sales agreements and a somewhat more conservative view on spot basis, we expect Seneca's realized gas price, before hedging for the last 9 months of the fiscal year, will range between $3.50 and $3.65 per Mcf and, again, this assumes a $4 NYMEX price. We were also active with our financial hedging program, adding roughly 12 Bcf of NYMEX gas hedges for fiscal '14 at a price of $4.39 per Mcf. As a result of the new firm sales and financial trades, we've now locked in pricing on about 80% of our production for the remainder of fiscal year. This high hedge percentage will limit, somewhat, the pricing upside during the next few quarters, but the hedges we have in place lock in great economics on our drilling program. We continue to monitor the NYMEX curve and are focused on adding new positions for fiscal '15 and beyond. We're keeping Seneca's production guidance the same at 145 to 165 Bcfe. And that's a little wider range than we typically have at this time of year, but we think it's appropriate, given the potential for pricing-related curtailments this summer. If we don't have a significant amount of curtailment, production will likely be above the midpoint of the range. With regard to capital spending, we're updating Utility's capital budget to reflect the additional $8.2 million of spending we agreed to as part of the new rate agreement. The new capital budget for the Utility is a range of $90 million to $100 million. The capital spending plans of the other segments have not changed from our previous guidance. With respect to our financing plans, the revisions to our earnings and capital spending guidance should not have a significant impact on our financing needs for fiscal '14. We still expect our CapEx and dividend will exceed our cash from operations by about $200 million to $225 million. Will that, I'll close and ask the operator to open the line for questions.

[Operator Instructions] And your first question comes from the line of Holly Stewart with Howard Weil.

Maybe, Ron, just first, on kind of Marcellus' hole in realizations, this is probably going to be hot topic for some time. There's just been a ton of volatility and all the different pricing points in the East, obviously due to weather. Can you just maybe just give us some color on what you guys are actually seeing out there? I guess, with lower storage levels, we would have thought, maybe, some of these differentials would have closed a bit at the different pricing points, it hasn't. So just any kind of color you could give us.

Sure. You might have thought that, Holly, and that -- conventional -- well, just sitting back and looking at it, that might seem like it should happen. But what we're seeing with everyone using their firm capacity, all the pipelines are pretty well full, moving FT gas. And for spot sales, to the extent you don't have that firm capacity and you're just trying to get into a pipeline anywhere, you're stuck with the spot pricing, which can be anywhere, as I mentioned in my comments, the differentials that we were seeing for term contracts were anywhere from $0.80 to $1.85, less the NYMEX. In some cases, they were a couple of dollars less than NYMEX. So it's really a matter, as Matt said, of not enough takeaway capacity with all the pipelines full, moving contract gas. That's the biggest cause for that phenomenon.

Okay, great. And then, Dave, I guess, you mentioned at the end, a lot of different comments on commitments and hedges. I know, initially, in your guidance, you had a $0.75 differential on non-contracted sales. Had did you do versus that during the first quarter?

The first quarter we actually weren't too far off from our -- from that assumption. It was a little weaker than that, but not dramatically so.

Okay. Just sub $1? Fair?

Yes. That'd be, say, between $0.75 to $1, depending on the pipeline.

Just to add to that, Holly, recognize that there are times when we curtail because the differential is too big in the spot market. So if you actually averaged what the differential was during the quarter, it would be bigger than that, but our realized differential was about $1.

Okay. So did you curtail anything during 1Q?

We curtailed about 2 Bcf during the quarter.

Okay. And then, maybe, just on the marketing division, can you talk about the dynamic in that business right now? Just with the volatility out there, it looks like your 1Q volumes are the largest we've seen in that business. I didn't know if there was any way to kind of capture some of that spread in that business.

I think, again, that business is based primarily on longer-term contracts with customers at fixed prices. So basically, NFR goes out and matches up hedges to cover its fixed price sales, so that the margin is pretty well set in that business. And what you're seeing in terms of volume is just an increase in -- as a result of the weather.

And the accounting change.

Or -- and the accounting change.

So remember, Holly, that's going to include -- the volumes will include 4 months' worth of the volumes.

Your next question comes from the line of Timm Schneider with ISI group.

I guess, as a follow-up to Holly's question, this is more macro-specific, I mean, what really needs to happen up in the Marcellus in order to fix these bases issues? Specifically, there's been a lot of talk on moving gas to the Midcontinent, moving gas down Southeast, moving gas up north to Canada and moving gas potentially to New England. Which of these options do you kind of see as the most viable, and maybe the most viable, for National Fuel Gas? And have you guys had any conversations with pipeline companies in terms of signing up for, I'd say, longer-term contract than some of this? And then, I have a follow-up.

Well, I mean -- I guess, Timm, all of those options are viable. The question is how quickly can they happen. As we mentioned, we've signed up on Atlantic Sunrise with Transco that moves gas down to the Southeast, but that's a...

2017.

2017 project. All of National Fuel Gas Supply Company's projects, which move gas either back to Canada or, again, down to the Texas Eastern project, those are a couple of years out. So it's really just a matter of getting the pipe in the ground. Longer term, the New England market probably is the largest market, but again, the more -- most difficult to get contracts signed up with shippers for a long-term contract. So it's just -- things that we're constantly working on. We've given as much visibility as we can with respect to our pipeline projects, but if you look at the slide deck, you can see those are only a couple of years out because it -- but we're constantly working for even more projects in the future.

Got it. Can you remind us what the -- what's the tariff that you guys are paying on Atlantic Sunrise.

I don't think that's been disclosed yet.

How about the one on the Niagara Expansion?

Yes, I mean, that's still early on. It's -- I mean...

I don't think that's been disclosed either, have you?

Yes.

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

Just maybe following up on Timm and Holly, and the bases as Holly said hot topic. Just back of the envelope math and assuming I heard you correctly, Ron, that we're looking at an extra -- that the Clermont to Chippawa was an incremental 100 million a day for basically an extra $100 million. You kind of slap some multiples on that and I would think you're probably looking at around the $0.40 range versus say for instance something Atlantic Sunrise which I guess would be much higher than that. And I guess, maybe the question is, with respect to that, are there any more $0.35, $0.40 type of expansions left? Or is everything from this point forward, such in the way of new build or greenfield that, that minimum $0.85 that you had quoted earlier basically now becomes the new floor for incremental FT?

Well, I mean, that's certainly what you see for the new builds and any kind of a project that you're going to be getting out there for sizable capacity, big capacity adds. I mean, you're talking about major length projects. So yes, I mean, it has the tweaking, let's say, of the system that we already have, get finished. You are looking at somewhere in the neighborhood of $0.85 for transportation costs on new build pipelines.

Okay, and I appreciate the color. And then, Matt, just with respect to the 4 to 5 delineation wells that are planned for the Marcellus through the year, how should we think of that, one, as far as timing, basically a new well drilled every 60, 90 days sort of going forward? And how long will it take to sort of get first result, at least in the public sphere?

We're on one of them now, the Sulger Farms well. So we'll have a test of that well by probably early fourth quarter. The others are all likely to be late this fiscal year or maybe even into the fall.

As far as public information or as far as actually drilling?

As far as having them frac-ed and tested. So yes, public information.

Ladies and gentlemen, that will conclude the question-and-answer session of today's call. I would now like to turn the call back over to Tim Silverstein for closing remarks.

Thank you, Philip. 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 14, 2014. To access the replay online, visit our Investor Relations website at investor.nationalfuelgas.com. And to access by telephone, call 1 (888) 286-8010 and enter passcode 73413175. This concludes our conference call for today. Thank you, and goodbye.

Ladies and gentlemen, that concludes today's conference. Thank you, all for your participation. You may all now disconnect. Have a wonderful week.