National Fuel Gas Company (NFG) Q2 2015 Earnings Report, Transcript and Summary

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. [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.

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.

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 benefited 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 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 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 filing for our Northern Access 2016 Project in mid-March. We had been in the prefiling process since last July, and we're pleased with the progress on the project so far. But we recognize that we have a tight time line 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-priced markets. As more and more pipeline capacity comes online, 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've taken on our Northern Access 2016 Project and Transco's Atlantic Sunrise project. Until that capacity comes online, Seneca is busy trying to find a home for some production that is otherwise subject to low spot pricing. Oil commodity prices were the biggest factor affecting our earnings for the quarter and our exploration of production business. Persistently low prices affected our results in 3 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 decrease in 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 2 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 online, we expect to see the basis differentials in our production areas decrease. We recognize that there will be some low spot pricing and curtailments that we need to deal with in 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.

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've 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 1. 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 a structured deal, which, starting today, May of 2015 and extending throughout March of 2017 at 50 million cubic feet per day of additional firm at a fixed price of $3. This deal provides immediate firm sales and pricing support at 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 Tract 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 thousand feet of lateral, this is one of the best IP rates for any Utica/Point Pleasant 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 Tract 007 area and another 15,000 acres nearby. We estimate the Utica resource potential at Tract 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 capacity is put into service. We see additional Utica potential a long trend at our Clermont/Rich Valley area and plan to drill 2 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 tie it 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 System. 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 3 horizontal rigs are currently all drilling Marcellus wells in the Clermont area, and we have plans to complete, drill out and bring online 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 3 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 2. 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 have firm 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 2 or even 3 shale horizons: the Marcellus, the Geneseo and of course, the Utica. And with that, I'll turn it over to Dave.

Thank you, Matt. Good morning, everyone. As you saw in last night's release, second quarter earnings were $0.20 a share, down $0.92 from last year largely because of an $0.82 ceiling test impairment charge. Under full cost accounting rules, the book value of our oil and gas properties can exceed the PV10 of our reserves at any quarter end. Because of the significant drop in prices, the book value of our properties exceeded PV10 at March 31. And therefore, under the rules, we were required to write down their value. It's important to note that this noncash impairment charge was entirely related to the decline in 12-month average pricing. In fact, our net reserve revisions for the quarter were a positive number. Excluding the ceiling test charge, earning -- 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 continue to see high demand for short-term transportation on our system. Some of it was weather-related, but most was producer volumes looking to get out of the basin. Though 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 benefited from a $4.5 million pretax adjustment that was recorded to true-up a 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 costs down, leading to improved F&D costs and a consistent decline in our DD&A rate, which dropped from $1.66 in the first quarter of fiscal '15 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 costs downward. Looking forward, our new earnings range for fiscal '15 is $2.75 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 any 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 assumes we curtail 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 6 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 6 months of the year, about 60%. And 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 a $2.75 per Mcf NYMEX price for the last 6 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 6 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 with the EOG Resources. Therefore, based on that 10 Bcf of spots 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 2 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 $1 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 an outspend that's in the range of $450 million, which we're planning to finance with a 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 Instructions] Our first question comes from the line of Carl Kirst with BMO Capital.

Matt, can I -- you had mentioned the $50 million a day of new hedging kind of beginning today, which is certainly great to see. Just for clarity, is that a netback? Is that a NYMEX? And I guess also, were there any costs associated with entering into that?

Yes. So Carl, that's realized price. We'll get $3 for our gas delivered at the point where the Clermont System hits Transco -- I mean, hits TGP. There's more to the deal. There's 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 a 41% IRR for our Clermont production. And then we get to this very favorable price in the near-term of $3.

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

Yes, 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.

Okay. No, that's helpful. And I had a question -- a 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 may be wrong, but I thought I potentially caught something with the Fish and Wildlife Service requesting the FERC do an EIS versus an EA. And I guess the question here really is do you guys see any potential delay risk beyond sort of the 2016 -- late 2016 in service date at this point?

Well, I mean, Carl, there's always a little bit of risk. As a matter of fact, the last 3 certificates that we got, I mean, those were delayed about a month from when we had originally expected them, maybe 1 month or 2. 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 3 projects. I don't -- we're not seeing it as a terribly big risk. But obviously, that's something that we've got to keep our eye on. The good thing about this project is there's a lot of rights of way that -- existing rights of way that we're following. We've only got 90 -- I think a little over 90 miles of a new, build right of way, and we've got the rights of way secured for the bulk of that. So sure, there's always some risk, but we think that's manageable.

Okay. Nothing you're seeing, as you said, terribly big risk, so that's very helpful, Ron.

Yes, no showstoppers.

Okay, okay. 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 taking the CapEx down for 2016, does that in any way impact your timing of looking at an MLP as a potential funding solution inasmuch as you guys have historically looked at that through a funding lens?

Well, I think, as we've said before, Carl, the MLP option is more tied to our spending in the Pipeline and Storage segment. So we're still targeting that and looking at the receipt of a certificate for Northern Access '16. And the funding of that $450 million project with that is an option there rather than funding Seneca's operations. Seneca, with the drop, we were 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.

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

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 sort of recompletions when you're putting that much back?

Short answer is no. Really no risk. And 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.

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

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

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

I just had a question real quick. Can you guide 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, quite a period to all that, so it takes a while. And then if you decide not to go with the MLP route, what's the funding route for Northern Access alternatively?

Well, the -- we were maybe 3 weeks late or so with the filing of the -- filing for the certificate from our original schedule. But we're still looking at a first calendar quarter '16 receipt, say, January of '16. And we'll have, obviously, plenty of liquidity on our short-term lines of credit to the extent we needed to prepurchase or acquire any pipeline or pipe or hardware for the project. But that's pretty much the time line 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's 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 the 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 '16.

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

I have a couple of follow-up questions. I guess, for Matt first, just trying to understand the 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 a 35 Bcf range, talking about that's what remains 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 were talking about, Carl, about for order of magnitude of 7 Bcf for the rest of the year. Does that, 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 sale -- fixed-price sale contract with that? Help me understand that.

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

Yes. It -- well, I guess, it's stated in a way would I, like, tally everything up at this point. I mean, it seems to me anyway that if we haven't have had the price situation that we had, the initial range that you gave for the year stands to reason we would be sort of in the upper half of that pretty comfortably.

That's true, yes.

Okay. And then, with regard -- I guess as a follow-on 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 at 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.

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 wanted to produce. But generally, what we do is we just -- they just sell that gas, and we get a revenue stream from it.

Okay. And Ron, I know we -- talking a lot about the cost reductions you guys have been able to achieve on the upstream side. Williams was talking probably yesterday about some cost improvement on one of their major project, the Atlantic Sunrise project, due to everything from labor availability to steel cost coming down. I'm just wondering, as it pertains to Northern Access '15 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?

Well, there may be some, Chris. But the -- I guess what's interesting is while we're 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's 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've got a -- they have a lot of business. So I -- we might see some, but I wouldn't count on an order of magnitude change in the overall pricing for that project.

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

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 3:00 p.m. 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.

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