National Fuel Gas Co (NFG) 2014 Q1 法說會逐字稿

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'll be your operator for today. At this time all participants are now in a listen-only mode. Later we will be conducting a question-and-answer session. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes.

I would now like to turn 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.

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 have all seen the recent volatility in daily spot pricing brought about by some of the recent winter storms. However, the former or 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 have 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 are seeing in the forward market it's likely that we will keep our rig count in Pennsylvania constant through this fiscal year. Even with a steady rig count, because of the efficiencies that we have 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 tariffs 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 have 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 have included that summary again in the updated slide deck that we put up on our webpage this morning. I am 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 on projects for Seneca particularly the build out of our Clermont Gathering System. And we have also got those plans laid out in our slide deck and we will have ongoing construction activities in 2014 and 2015 and will 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 looked 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 will see that we have 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.

So 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 have 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 Sespe pipeline issue has been resolved. Sespe production is now up to 1400 barrels of oil equivalent per day as compared to 1100 two months ago.

At South Lost Hills, we are drilling our second fiscal 2014 horizontal Monterey Shale well. Both of these two wells will be fracked and tested in the third quarter. We also have drilling planned at Sespe, South Midway Sunset, and East Coalinga fields. For the fiscal year, we expect California production to grow by about 5% versus fiscal 2013.

In Kansas, we have completed our first horizontal well and are drilling our second. The first well is testing and the second will be fracked 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 six new wells at Pad N came on at an average 24 hour peak rate of 15.6 million cubic feet per day. Five 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 to drill and complete the six 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 nine well development pad and we are drilling the fourth of six wells on a 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 three 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 Farms area. We expect to drill four to five Marcellus delineation wells this year and one Utica delineation well.

Looking at production for the remainder of fiscal 2014, 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 0.5 Bcf a day sometime in the fourth quarter and company-wide production should average over 0.5 Bcf a day for the fourth quarter barring any significant price related curtailments.

As I am sure you are 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 of 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 are 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 two 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 is 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 forecasts and there were three 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 nonregulated energy marketing subsidiary, we had a change in the way we recorded revenue.

Previously NFRs revenues were recorded on a one-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 pipeline has seen terrific demand for capacity from both producers and from marketers that are responding to the colder weather and available basis spreads.

In addition to the larger projects we have built, our marketing team is done a great job selling every last bit of available space on our system. As a result, revenues for the quarter 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 a range of $270 million to $275 million which at the midpoint is a modest increase from fiscal 2013.

At Seneca, per unit expenses were a little lower than expected but significantly below last year's levels. In fact on a per unit basis, our combined DD&A, LOE and G&A were $0.48 per Mcfe, or 13% lower than the first quarter of fiscal 2013. 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 a 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 prices. 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 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 has 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 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 a third of our customer base the impact tends to be pretty small.

The 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 to the proceeding. Therefore we are accounting for it as of that day. The major financial terms of the agreement which contains a two-year stay out provision are as follows.

First, we agreed to approve $7.5 million to settle all allegations concerning past earnings including both the temporary rate proceeding and the Section 6620 retroactive proceeding. As you will 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 assets 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 target is 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 nonfinancial provisions of the settlement related to safety standards, service quality and other items and I won't review those here. If you are interested you can get a copy of the term sheet from the Commission's website or from Tim.

Switching to earnings guidance, we are narrowing our fiscal 2014 earnings expectations to range of $3.20 to $3.40 per share at the midpoint of $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 a 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 2014 at a price of $4.39 per Mcf. As a result of the new firm sales and financial trades we have now locked in pricing on about 80% of our production for the remainder of the fiscal year. This high hedge percentage will limit somewhat the pricing upside during the next few quarters but the hedges we have in place locking great economics on our drilling program. But we continue to monitor the NYMEX curve and are focused on adding new positions for fiscal 2015 and beyond.

We are keeping Seneca's production guidance the same at 145 Bcfe to 165 Bcfe and that is a little wider range than we typically have at this time of the year but we think it is appropriate given the potential for pricing-related curtailments this summer. If we don't have a significant amount of curtailments, production will likely be above the midpoint of the range.

With regard to capital spending, we are updating the 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 for 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 2014 but we still expect our CapEx and dividend will exceed our cash from operations by about $200 million to $225 million.

With that, I'll close and ask the operator to open the line for questions.

(Operator Instructions). Holly Stewart, Howard Weil.

Good morning, gentlemen.

Good morning, Holly.

Maybe, Ron, just first on kind of the Marcellus as a whole one realization, this is probably going to be a hot topic for some time. There has 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 of thought maybe some of these differentials would have closed a bit at the different pricing points but haven't. So just any kind of color you could give us?

Sure. You might have thought that, Holly, and the conventional -- just sitting back and looking at it, that might seem like it should happen. But what we are seeing with everyone using their firm capacity, all the pipelines are pretty well full moving FT gas. And for spots sales to the extent you don't have that firm capacity and you are just trying to get into a pipeline anywhere you are 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 than NYMEX and in some cases, they were a couple of dollars less than NYMEX.

So it is really a matter, as Matt said, of not enough take away capacity with the -- 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. How did you do versus that during the first quarter?

Yes, 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 so sub $1? Fair?

Yes, that would be say between $0.75 and $1 depending on the pipeline.

Okay, perfect.

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, thank you. And then maybe just on the marketing division, can you talk about the dynamics in that business right now? Just with the volatility out there, it looks like your 1Q volumes were the largest we've seen in that business so 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 are seeing in terms of volumes is just an increase as a result of the weather.

And the accounting change.

And the accounting change.

Yes, so remember, Holly, that's going to include -- the volumes will include four months worth of volumes.

Okay, got it. Okay, thanks, guys.

Timm Schneider, ISI Group.

Hey, good morning, guys. 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 basis issues? Specifically there has been a lot of talk on moving gas to the Mid-Continent, 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 potentially longer-term contracts on 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 have signed up on Atlantic Sunrise with Transco that moves gas down to the Southeast. But that is 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 is 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 most difficult to get contracts signed up with shippers for a long-term contract. So it is just -- things that we are 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 but we are constantly working for even more projects in the future.

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

That hasn't been disclosed yet.

How about the one on the Niagara Expansion?

Yes, I mean that is still early on. I mean --

I don't think that has been disclosed either.

Okay, got it. I'll jump back in the queue. That is it for me for now. Thanks.

Carl Kirst, BMO Capital.

Thanks, good morning everybody. Just maybe following up on Timm and Holly and the basis as Holly said, a hot topic. You know just back of the envelope math assuming I heard you correctly, Ron, that we are looking at an extra -- the Clermont to Chippawa was an incremental 100 million a day for basically an extra $100 million. You kind of slapped some multiples on that and I would think you are probably looking at around a $0.40 range versus say for instance something Atlantic Sunrise which I guess would be much higher than that.

Then I guess maybe the question is respective of 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 newbuild 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 is certainly what you see for the newbuilds and any kind of a project that you are going to be getting out there for sizable capacity, big capacity adds I mean you are talking about major length projects.

So yes, I mean as the tweaking let's say of the system that we already have gets finished, you are looking at somewhere in the neighborhood of $0.85 for transportation cost on newbuild pipelines.

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

We are on one of them now, the Sulger Farms well, so we will 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 fracked and tested. So yes, public information.

Great, thanks so much guys.

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 PM 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.