National Fuel Gas Company
Q1 2015 Earnings Call Transcript

Published: 1 May 2015

[Operator:]

Good day, ladies and gentlemen, and welcome to the Q2 2015 National Fuel Gas Company Earnings Conference call. My name is Lily, and I’ll be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct the question-and-answer session. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I will now turn the conference over to your host for today, Mr. Brian Welsch, Director of Investor Relations. Please proceed.

[Brian Welsch:]

Thank you, Lily, 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 up the discussion to questions. Last night, 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.

[Ron Tanski:]

Thanks, Brian. And good morning, everyone. Given the lower commodity prices that we saw during the quarter, our operating results of $86 million reflect a really solid performance from each one of our operating segments. Our utility employees did a great job running our system during another harsh winter and our customers benefitted from continued low unit pricing due to the availability of cheap supplies of shale gas. We had another winter quarter where new temperature records were set in our utility service territory. But if you recall, we set records in the last year also. As a result, earnings in our utility business were up modestly over last year. We continue to move forward with our plans to grow our pipeline business. We received FERC certificates for each of our West Side Expansion, Tuscarora Lateral and Northern Access 2015 projects and construction is underway for each of those projects with targeted completion dates either a late this fiscal year or in the first quarter of next fiscal year. We’re projecting an increase to our annual revenues of approximately $33 million from these projects, beginning next fiscal year. We also submitted our formal FERC filings for a Northern Access 2016 project in mid-March. We had been in the pre-filing process since last July and were pleased with the progress on the project so far but we recognize that we have a tight timeline to get the project in service by our targeted date of November 2016. You may have noticed that we upsized our capacity on this project from 350,000 dekatherms per day to 497,000 dekatherms per day. Our engineers were able to redesign Seneca’s compression facilities to deliver gas at a higher pressure into the pipeline. And this will allow Seneca to ship more production on this project. All of these projects are designed to move production for Seneca and other third parties out of the basin to higher price markets. As more and more pipeline capacity comes on line, we expect Seneca’s pricing realizations to improve. Seneca continues to become more efficient in drilling and completing wells. Our drilling and completion schedule is designed for Seneca to be able to fill the firm capacity that we have taken on our Northern Access 2016 project and Transco’s Atlantic Sunrise project. Until that capacity comes on line, Seneca’s busy trying to find a home for some production that is otherwise subject to low spot pricing. Low commodity prices were the biggest factor affecting our earnings for the quarter in our exploration and production business. Persistently low prices affected our results in three ways. First, the lower unit pricing reduced the revenues for the production that we did sell; second, spot pricing for the production that was not committed under a sales contract, decreased to the point that we elected to curtail that production, so our production volumes were lower; and third was the ceiling test charge that we were required to take under the SEC full cost accounting rules, as a result of the decreasing commodity prices over the past 12 months. Matt will provide some more details regarding our hedging and marketing efforts at Seneca and Dave will provide a few more details on the ceiling test later in the call. Overall, I’m very pleased with the operations of each of our segments during the past quarter. We’ve continued to execute on all our plans as we’ve discussed with the investment community over the past two years and will continue to do so for the foreseeable future. On a macro basis, we continue to see more and more drilling rigs being idled and we believe that this will help bring the current oversupply more in balance with near-term demand. And as each new pipeline project out of the basin comes on line, we expect to see the basis differentials in our production areas decrease. We recognize that there will be some low spot pricing in curtailments that we need to deal within the short-term but we anticipated that and our plans are designed to deal with that issue. We’ve got a strong balance sheet and plenty of liquidity that will allow us to follow through with our plans. Now, I’ll turn the call over to Matt.

[Matt Cabell:]

Thanks Ron and good morning everyone. For the fiscal second quarter, Seneca produced 35.7 Bcfe or 3% less than last year’s second quarter. However, during the second quarter of ‘15, we sold only our firm volumes in the Marcellus and curtailed 13.5 Bcf or approximately 150 million cubic feet per day of potential spot sales due to low prices. Absent those curtailments, production would have been up 34%. We have firm sales for a substantial portion of our fiscal 2015 and fiscal 2016 production. And for the majority of those firm sales, we have associated hedges. For the second quarter, that resulted in an after hedging gas price of $3.65 per Mcf. We continue to utilize a portfolio approach to maximize the value of our significant firm transport position which has included fixed priced firm sales starting prior to the in service date of a new pipeline project. A year ago, this approach allowed us to negotiate a contract to sell 50 million cubic feet per day of our Lycoming production from November of 2014 through October of 2017 at a fixed price of $3.77. This compares favorably to Leidy line spot prices which averaged $1.36 since January 1st. Last week, we took another positive step in creating additional price certainty. This time for our Clermont and Tioga production which today flows into Tennessee 300. We negotiated structured deal which starting today, May of 2015 and extending through March of 2017 adds 50 million cubic feet per day of additional firm at a fixed price of $3. This deal provides immediate firm sales and pricing support and an attractive level until Northern Access 2016 goes into service. Future deals we enter into will focus on maximizing value to Seneca during the 15-year term of our capacity. And we still have some 415 million cubic feet per day of Northern Access 2016 capacity to optimize through this portfolio approach. Inclusive of this most recent transaction, we now have almost 100 Bcf of fiscal 2016 gas production, locked in at an average price of $3.60 per Mcf. Moving on to the Utica. In Tioga County, we tested our Track 007 Utica well at a 24 hour rate of 22.7 million cubic feet per day from a relatively short lateral of 4,600 feet. On an initial rate per 1,000 feet of lateral, this is one of the best IP rates for any Utica point present well, surpassing all but a few of the high rate wells drilled in Eastern Ohio and Southwest Pennsylvania. We hold approximately 10,500 acres in the Track 007 area and another 15,000 acres nearby. We estimate the Utica resource potential of Track 007 alone to be over 1 trillion cubic feet. We will likely begin development of the area in 2017 when we expect a significant improvement in Northeast Pennsylvania spot pricing as new pipeline capacities put into service. We see additional Utica potential a long trend at our Clermont Rich Valley area and plan to drill two Utica wells there in fiscal 2016 in conjunction with our ongoing Clermont Marcellus development. This will allow us to drill each Utica appraisal well on a multi well pad and tied into the Clermont gathering system. This approach will enable us to materially reduce drilling and completion costs and immediately take advantage of our firm transportation by producing our Utica appraisal wells into the Clermont gathering systems. We anticipate the initial flow test from the first well in the third quarter of fiscal ‘16 and the second well toward the end of fiscal ‘16. Our three horizontal rigs are currently all drilling Marcellus wells in the Clermont area and we have plans to complete drill out and bring on line approximately 30 new wells into the Clermont system by November when Northern Access 15 is expected to be in service. Seneca holds 158 million cubic feet per day of firm transportation capacity on this project. Drilling and completion efficiencies will allow us to reach our production targets with fewer rigs and reduced CapEx. Over the past three years, we have cut our well cost by 28% while increasing the lateral length by 41%. Such that our cost per foot of lateral is roughly half of what it was in 2012. Year-to-date in fiscal 2015, our average well has a completed lateral length of 7,200 feet and a total cost of $6.3 million. Because of this improved efficiency, in the second quarter of ‘16 we plan to drop one horizontal rig, reducing our rig count to two. Our fiscal 2016 CapEx forecast is $400 million to $475 million, a 20% reduction as compared to fiscal 2015. In summary, we are continuing to execute the plan in part due to the steps we have taken to insulate Seneca from current low natural gas prices and take away constraints. We affirm sales and associated hedges from a majority of our forecasted 2015 and 2016 production. And in early fiscal 2017, we will have over 700, 000 dekatherms of firm transportation to premium markets. We have a deep inventory of Marcellus drilling locations and in some areas we have potential in two or even three shale horizons, The Marcellus; the Geneseo and of course the Utica. And with that I’ll turn it over to Dave.

[Dave Bauer:]

Thank you, Matt. Good morning, everyone. As you saw in last night’s release, second quarter earnings were $0.20 per share, down $0.92 from last year largely because of $0.82 ceiling test impairment charge. Under full cost accounting rules, the book value of our oil and gas properties can exceed the PV-10 of our reserves at any quarter-end. Because of the significant drop in prices, the book value of our properties exceeded PV-10 at March 31st and therefore under the rules we were required to write down the value. It’s important to note that this non-cash impairment charge was entirely related to decline in 12-month average pricing. In fact, our net reserve revisions for the quarter were a positive number. Excluding the ceiling test charge, operating results were down from the second quarter of 2014. As Ron indicated, lower commodity prices were the main driver of our weaker results. After hedging, oil prices were down nearly $30 a barrel and gas prices were down $0.24 per Mcf. Combined, these price drops, impacted earnings by about $0.22 per share. Putting aside the drop in commodity prices, it was a good quarter for the company, particularly at our regulated businesses. In the pipeline and storage segment, revenues were up $3 million over our internal estimates. As in prior quarters, we continued to see high demand for short-term transportation on our system. Some of it was weather related but most was producer volume looking to get out of the basin. So, it’s not, obvious from last night’s release, our utility had a terrific quarter as well. The weather in our Pennsylvania service territory while only 2.5% colder than last year was 23% colder than normal which added about $0.04 per share to earnings relative to our forecast. And remember, our forecast assumes normal weather. Also earnings in our New York jurisdiction benefitted from a $4.5 million pretax adjustment that was recorded true up our receivable from customers for a state regulatory assessment. Moving to the E&P business, Seneca’s focus on drilling and completion efficiencies have driven well cost down leading to improved F&D costs and a consistent decline in our DD&A rate, which dropped from a $1.66 in the first quarter of fiscal 2015 to the $1.61 we saw this quarter. A good example of these efficiencies is our Clermont-Rich Valley area where our proved undeveloped reserves are booked at an average F&D cost of $0.90 per Mcf and that’s based upon historical capital costs and P90 EURs. Continued operational efficiencies coupled with vendor concessions should continue to drive our Clermont F&D cost downward. Looking forward, our new earnings range for fiscal 2015 is $2.75 per share to $2.90 per share. It’s important to note that our updated guidance excludes both the ceiling test charge we recorded this quarter and then future ceiling test impairments we may record later in the year. If oil and natural gas prices do not recover significantly from the current strip, we do expect further impairments. In addition to reflecting our results for the second quarter, our guidance incorporates several other changes and assumptions. Seneca’s updated production forecast is now 155 to 175 Bcfe. We lowered the high-end of our previous 155 to 190 Bcfe range to reflect the 13.5 Bcf of estimated curtailments for the second quarter. The difference between the high and low end of our production range is driven entirely by curtailments. The low end assume we curtail a 100% of our spot production while the high end assumes we have no curtailments. We’ve also updated our commodity price assumptions. Our forecast now reflects a NYMEX oil price of $60 a barrel for the last six months of the year, up from $50 in our previous forecast. However, the earnings impact of this change will be fairly minimal, for one we’re fairly well hedged for the last six months of the year about 60% and then in addition, refinery outages in Southern California have weakened physical pricing differentials below our prior forecast, which offset some of the uplift from the higher WTI prices. Turning to natural gas, we’re assuming $2.75 per Mcf NYMEX price for the last six months of the fiscal year, down from $3. However, because substantially all of Seneca’s firm sales have been hedged, changes in NYMEX gas prices will have a minimal impact on our earnings for the second half of the year. With respect to spot prices, our updated guidance assumes we sell our Marcellus spot production for between $1.75 and $2 per Mcf, down $0.25 from our previous guidance. The midpoint of our new production guidance assumes that for the last six months of the year, we have about 10 Bcf of spot sales of which about 6 Bcf is from our own operations and 4 Bcf is from our joint venture of EOG Resources. Therefore, based on that 10 Bcf of spot sales, every $0.25 in the average spot price will impact earnings by about $0.02 per share. And as a reminder, because we curtail production when prices get too low, this spot price assumption is only for the volumes we actually sell into the market. Seneca should see some improvement in its per unit operating expenses during the last few quarters of the fiscal year. LOE expense for the second quarter was $1.16 per Mcfe, up from $0.97 in the first quarter. While some of that increase was attributable to winter road maintenance in the eastern development area, most of it was due to the 13.5 Bcf of pricing related curtailments. Absent those curtailments, per unit LOE would have been in the low dollar per Mcfe area. Looking forward, assuming the 165 Bcfe midpoint of Seneca’s production guidance, we expect our full year LOE expense will be a little over the midpoint of our $1 to $1.10 per Mcfe guidance. We’re now forecasting Seneca’s per unit DD&A rate at a range of $1.55 to $1.65 per Mcfe. As I mentioned earlier, lower drilling and completion costs have had a favorable impact on Seneca’s rate and we expect that trend will continue. Also it’s important to note that while our DD&A guidance reflects the impact of the ceiling test impairment we recorded this quarter, it does not incorporate any future ceiling test charges. Lastly, in the pipeline and storage segment, on the strength of an excellent second quarter and the prospects for continued demand for short-term transportation services, we’re upping our expected revenues to a range of $280 million to $290 million. With respect to financing needs, our overall plans have not changed. Consolidated capital spending for fiscal ‘15 is expected to be in the range of $990 million to $1.155 billion, unchanged from our previous guidance. We had a good second quarter and have revised a number of earnings related assumptions but given our high hedge percentage, we’re not expecting any significant change in cash from operations. We still expect to an outspend that’s in the range of $450 million, which we’re planning to finance with the long-term debt issuance in the months to come. The ultimate timing of that issuance will depend on market conditions. With that, I’ll close and ask the operator to open the line for questions.

[Operator:]

[Operator Instructions]. Our first question comes from the line of Carl Kirst with BMO Capital. Please proceed.

[Carl Kirst:]

Matt, can I -- you mentioned the 15 million a day of new hedging kind of beginning today which is certainly great to see. Just for clarity, is that a net back; is that a NYMEX; and I guess also was there any cost associated with entering into that?

[Matt Cabell:]

So Carl, that’s a realized price; we’ll get $3 for our gas delivered at the point where the Clermont system hits Transco -- I mean hits TGP. There is more to the deal. There is also 75 million a day of indexed sales beginning in April 2017 goes for 7.5 years at that point. That 75 million will be at a Dawn Index and it’s got a cap of $4. So essentially, what we get is a very favorable price that even at that cap of $4, we’re at 41% IRR for our Clermont production and then we get this favorable price in the near-term of $3.

[Carl Kirst:]

And Matt, that $4 cap in the future, that would be a $4 Dawn price?

[Matt Cabell:]

It’s a little more complicated than that but we actually get the benefit of a premium at Dawn relative to NYMEX and we could get hurt a little on a deficit to NYMEX but -- so think of it as a $4 NYMEX cap but it’s priced at Dawn if that makes sense.

[Carl Kirst:]

And kind of question follow-up question on Northern Access 2016. And I guess generally, we’ve certainly seen infrastructure get impacted by regulatory delays, et cetera and I maybe wrong but I thought I potentially caught something with the Fish and Wildlife Service requesting the FERC do an EIS versus EA. And I guess maybe the question here really is do you guys see any potential delay risk beyond sort of the 2016 -- late 2016 in-service data at this point?

[Ron Tanski:]

Carl, there is always a little bit of risk. As a matter of fact, the last three certificates that we got, I mean those were delayed about a month from when we had originally expected that maybe a month or two, it put us a little bit under the gun to get timber cleared before we ran into a moratorium because of the long-eared bat migration but we were able to get that done for those three projects. I don’t -- we’re not seeing it as a terribly big risk but obviously this is something that we’ve got to keep our eye on. The good thing about this project is there is a lot of rights of way that -- existing rights of way that we’re following. We’ve only had 90 -- I think a little over 90 miles of new builds right away and we’ve got the rights of ways secured for the bulk of that. So sure, there is always some risk, but we think that’s manageable.

[Carl Kirst:]

Nothing you are seeing, as you said terrible big risk. So that’s very helpful, Ron.

[Ron Tanski:]

No show stoppers.

[Carl Kirst:]

And then maybe lastly, just to ask with the dropping because of the efficiencies with the dropping of the rigs from 3 rigs to 2 rigs and you taking the CapEx down for 2016, does that in anyway impact your timing of looking at an MLP as a potential funding solution and as much as you guys have historically looked at that through a funding lens?

[Ron Tanski:]

I think as we’ve said before Carl, the MLP option is more tide to our spending in the pipeline and storage segment. So, we’re still targeting that looking at the receipts of the certificate for Northern Access 2016 and the funding of that $450 million project with that as an option there, rather than funding Seneca’s operations. Seneca with the drop, we’re hoping to be -- have pretty much living within cash flow in 2016. So, it’s really the pipeline project that’s determining that rather than Seneca’s drilling.

[Operator:]

Your next question comes from the line of Kevin Smith with Raymond James. Please proceed.

[Kevin Smith:]

Matt, are there any structural problems curtailing this month’s production? I know it really is more impactful on the oil side, but just trying to think is there a possibility of losing reservoir pressure having to do any full recompletions, when you put much back?

[Matt Cabell:]

Short answer is no, really no risk. In fact, the way we determine what and when we’re going to curtail, first priority is always no negative impact to long-term operations.

[Kevin Smith:]

And then given the lower well cost and completion, are we going to see any cost savings show up in your CapEx budget in the form of less spending this year; how are we thinking about that?

[Matt Cabell:]

I think our efficiency gains and our vendor negotiations are all reflected in the current CapEx guidance.

[Operator:]

Your next question comes from the line of Timm Schneider with Evercore. Please proceed.

[Timm Schneider:]

I just had a question real quick, can you walk us through the time line of the certificates for Northern Access 2016? And with that, at which point would you guys have to start the kind of initiating the MLP process, because there is obviously a quiet period, so that takes a while. And then if you decide not to go the MLP route, what’s the funding plan for Northern Access alternatively?

[Ron Tanski:]

We were maybe three weeks late or so with the filing for the certificate from our original schedule but we’re still looking at a first calendar quarter ‘16 receipts, say January of 2016. And we’ll have obviously plenty of liquidity on our short-term lines of credit to the extent we needed to pre-purchase or acquire any pipeline or pipe or hardware for the project. But that’s pretty much the timeline we’re still looking for working toward our examination or let’s say the details of an MLP option. To the extent we chose not to do an MLP, there is any number of other, say either joint venture on the upstream, so that if we didn’t spend our own money drilling the wells with Seneca, we could use a joint venture funds for that and then allocate that capital to the pipeline. But we’re -- as we look at it right now, our plans still envision the MLP as probably the most likely way of financing the building of Northern Access 2016.

[Operator:]

[Operator Instructions] Your next question comes from the line of Chris Sighinolfi with Jefferies. Please proceed.

[Chris Sighinolfi:]

I have a couple of follow-up questions, I guess for Matt first. Just trying to understand that curtailment range. I know Dave spoke about what remains in terms of the bucket of curtailments for the year but just trying to jive that with what we heard last quarter. Last quarter, for example, you guys gave 35 Bcf range talking about that’s what remained for the year. We saw 13.5, last quarter and the top end of the guidance came down by about that amount. But then you added this contract that you’re talking with Carl about for order of magnitude 7 Bcf for the rest of the year. Does that mean like in effect mean the range got a little bit wider or how do we think about the context of that contract with the firm fixed price sales contract with that? Help me understand that.

[Matt Cabell:]

I guess the way I would put it is the firm contract gave us complete certainty -- well maybe complete is wrong word but essentially gave us certainty around the bottom-end of the guidance by adding 7.5 Bcf firm, so some uncertainty would be above that bottom end of guidance, at least a little.

[Chris Sighinolfi:]

I guess stated another way, would I tally everything up at this point, I mean it seems to me anyway that if we hadn’t had the price situation that we had, the initial range that you gave for the year stands the reason we would be sort of in the upper half of that pretty comfortably.

[Matt Cabell:]

That’s true.

[Chris Sighinolfi:]

And then, with regard -- I guess following to Kevin’s question about the impact of curtailment. When you speak about the JV with EOG, who makes the decisions on that whether or not to sell a spot? Is that you or is that a discussion with them; how does that process work? I realize it’s small but I was just curious.

[Matt Cabell:]

EOG makes that decision. I think the contract probably would allow us to take our gas in kind maybe if they wanted to curtail and we want to produce. But generally, what we do is we just -- they just sell that gas and we get a revenue stream from it.

[Chris Sighinolfi:]

And Ron, I know we’ve spoken a lot about the cost reductions you guys have been able to achieve on the upstream side. Williams was talking on their call yesterday about some cost improvement on one of their major projects, the Atlantic Sunrise project due to everything from labor availability to steel costs coming down. I’m just wondering as it pertains to Northern Access 2016 being the largest project you guys will undertake, are there opportunities do you think in this environment for the cost as advertised on that system, to come down at all?

[Ron Tanski:]

There may be some Chris, but I guess what’s interesting is while we were in the planning stages for that project, we had to revise our estimates up because of bids from the contractors that -- initial bids that were coming in that were higher than our original estimates. Now you’re right, the things in the industry certainly on the upstream side have changed but it hasn’t changed all that much on the midstream side. There is a lot of projects out there that are on the drawing boards and recently at an INGAA meeting which was a joint meeting with the foundation which all the members are mostly pipeline contractors, everyone is very upbeat about their business and they have a lot of business. So we might see some but I wouldn’t count on an order of magnitude change in the overall pricing for that project.

[Operator:]

Ladies and gentlemen, that concludes our Q&A. I’ll now turn the call back over to Brian for closing remarks.

[Brian Welsch:]

Thank you, Lily. 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, May 8, 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 60939904. This concludes our conference call for today. Thank you and goodbye.

[Operator:]

Ladies and gentlemen, that concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day.