National Fuel Gas Company (NFG) Q4 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Quarter 4 2014 National Fuel Gas Company Earnings Conference Call. My name is Cathy, and I will be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I would now like to turn the call over to Brian Welsch, Director of Investor Relations. Please proceed, sir.

Thank you, Cathy, and good morning. We appreciate you joining us on today's conference call for a discussion of last evening's earnings release. With us on the call today from National Fuel Gas Company are Ron Tanski, President and Chief Executive Officer; Dave Bauer, Treasurer and Principal Financial Officer; and Matt Cabell, President of Seneca Resources Corporation. At the end of the prepared remarks, we will open the discussion to questions. This morning, we posted a new slide deck to our Investor Relations website. We may refer to it during today's call. We would like to remind you that today's teleconference will contain forward-looking statements. While National Fuel's expectations, beliefs and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last evening's earnings release for a listing of certain specific risk factors. With that, I'd turn it over to Ron Tanski.

Thanks, Brian, and good morning, everyone. Thanks for joining us today for a discussion of the results of another really good fiscal year. Our operating results for the entire fiscal year exceeded last year by 8%, with strong results from each of our reporting segments. I'll let Dave Bauer cover specific details for the fourth quarter. But if you look at the results for the entire fiscal year, it's easy to see 3 main drivers to earnings changes across the system. First was the increase in throughput in our Midstream businesses. That increased throughput on both the interstate pipeline system and on our Gathering systems was the biggest driver for our increase in earnings for the year. Second, the coldest winter in 50 years in our utility service territory, coupled with a larger pension expense resulting from our last New York rate case settlement, caused an increase in our operation and maintenance expenses that lowered earnings in the utility segment. Third was the decrease in commodity prices after hedging in our Exploration and Production segment. Natural gas prices were down 13.1%, and oil prices were down 2.7% from the previous year. Both Dave and Matt will get into more detail regarding the numbers, but when you step back and look at operations across the entire company, you see a great picture. Our consolidated earnings from continuing operations reached a record high for the company in fiscal 2014. Net income was higher and only one time in 2007 when we had a $120 million gain from the sale of our Canadian Exploration and Production operations. Cash flows also reached a record high despite lower commodity prices. Looking forward, we're really pleased with the opportunities that we have before us and our plans to capitalize on them. Starting with our Upstream business, the continued development of our high-quality, Clermont/Rich Valley acreage will be keeping Seneca busy. The continuous nature of this acreage has allowed us to drill these wells efficiently and drive down the cost of the wells to an average of around $6.5 million per well. Our fee ownership of the minerals on this acreage boosts our economics and will allow us to keep 3 rigs active even at the lower commodity prices that we're experiencing in the near term. We had a great construction season for our gathering company, the trunk line and lateral pipeline segments and compressor stations for the Gathering system across the Clermont/Rich Valley acreage are all going in on schedule. Things are also going well in the regulated pipeline business. Just last week, we commissioned our new Mercer compressor station, and we're now moving an additional 100,000 decatherms per day for Range Resources across our system and into the Tennessee gas pipeline system. We expect to receive a FERC certificate for our Northern Access 2015 Project this month, and we're planning to have that project in service next November. The Northern Access 2016 Project is also moving along according to plan. The one thing that is not going entirely according to plan is commodity pricing. As you saw in our release last evening, we're reducing our fiscal 2015 earnings guidance range by $0.25 per share. That reduction is due solely to oil and gas pricing in the spot markets that we're seeing in the near term. As we've talked about many times before, we have a partial solution to our spot market pricing problem, kicking in during 2015 when Seneca picks up more firm capacity to the Canadian markets on our Northern Access 2015 Project. Further pieces fall into place in fiscal 2017 when our capacity on each of the Northern Access 2016 and Atlantic Sunrise projects come online. While we're always careful with our spending, with the current dip in commodity pricing, we're going to be paying even more attention to the timing of our spending, which Matt will discuss in just a bit. As I mentioned during our call last quarter, we were going to take a closer look at an Upstream mineral interest master limited partnership to see if it could be a good fit for a financing for us. Given the volatility that we've seen in the Upstream MLP market and the ongoing prices -- pricing basis challenges in the Marcellus, we don't think it's the right time for us to go down the Upstream MLP path. We are, however, continuing to work on our evaluation of the Midstream MLP. As I mentioned, during our last call, construction of our Northern Access 2016 Project, which has a price tag north of $400 million, would likely set the stage for a Midstream MLP financing. We're still in the prefiling stage with FERC for that Northern Access Project, but our environmental work seems to be going well. We hope to be in a position to file for our FERC certificate during the first calendar quarter of 2015, and we're still targeting January 2016 for the receipt of a FERC approval that would allow construction to begin. Until then, our strong balance sheet and credit capabilities should carry us through our 2015 fiscal year. Now I'll turn the call over to Dave Bauer to give a little more color on our quarterly results.

Thank you, Ron, and good morning, everyone. Considering the drop in commodity prices, the fourth quarter was a good conclusion to an outstanding fiscal year. As you read in last night's release, our earnings on an operating results basis were $0.60 per share. In the big picture, there were 3 main drivers of our earnings this quarter. The first is increased volumes across our system. Seneca's production for the quarter was up 38% over last year, even though about 5 Bcf of pricing-related curtailments pushed us towards the lower end of our production guidance. In addition to benefiting Seneca, this increase in production had a significant impact on the earnings of our Gathering business, which more than doubled from the prior year. On top of that, our FERC-regulated Pipeline and Storage business had another quarter with earnings up $0.04 per share. Going in the other direction, the continued decline in commodity prices weighed heavily on Seneca's earnings. For the quarter, Seneca's after hedging natural gas prices were down $0.80 per Mcf from the prior year, and after hedging oil prices were down $5.50 per barrel. Combined, these price drops reduced Seneca's earnings by about $0.28 per share, which more than offset the benefit to earnings of increased production. Lastly, earnings in the utility were down $0.08 per share from the prior year, largely due to our new rate agreement in New York, which as Ron said, reduced our stated ROE to 9.1%, largely through increased recognition of pension and postretirement benefit expenses. Higher bad debt expense also contributed to the decrease in earnings of the utility. In last year's fourth quarter we recorded a $5 million downward adjustment to our reserve for bad debts. No similar adjustment was required in this year's fourth quarter. The remainder of our earnings variances are described in last night's earnings release, so I won't repeat them all here. Instead, I'll focus on our guidance for fiscal '15. As we said in last night's release, our new range for fiscal '15 is $3.05 to $3.35 per share at the midpoint, down $0.25 from our previous guidance. Substantially, all of the change is attributable to a decrease in the commodity price assumptions reflected in the forecast. Specifically, we're now assuming NYMEX crude oil prices average $85 a barrel, down $10 from the previous forecast. At the midpoint, this change reduced our earnings expectations by approximately $0.10 per share. Oil has traded off even further from this level, but the same relative sensitivity applies, namely a $5 change in oil prices that will impact earnings by about $0.05 per share. We're also lowering our fiscal '15 NYMEX natural gas price assumption to $4 per MMBtu, down $0.25 from the previous forecast. With respect to Seneca's firm sales volumes, this change will have a have minimal impact on earnings since substantially all of those firm sales have been hedged. However, with respect to spot natural gas pricing in the Marcellus, with this price change, we're now assuming we receive, on average, between $2.50 and $2.75 per Mcf, down $0.25 per Mcf from our previous guidance. At the midpoint, this change reduced earnings our expectations by approximately $0.14 per share. Marcellus spot pricing has been extremely volatile. For example, this past Tuesday, we sold spot production for an average of about $2.35 per Mcf. A little cold weather can make a big difference. Today, we're selling production at over $3.40 an Mcf. This volatility will almost certainly continue, and we'll revise our pricing assumptions in the coming quarters if it's appropriate. For fiscal '15, we have approximately 66 Bcf of production exposed to the spot market, so changes in spot pricing could have a meaningful impact on our earnings. For every $0.10 change in the average spot price, earnings are impacted by about $0.05 per share The remainder of our fiscal '15 forecast is largely unchanged. A brief recap of the major assumptions by segment is as follows. At Seneca, oil and gas production is expected to be 180 to 220 Bcfe. Thanks to strong reserve bookings at year end, DD&A expense should now be in the range of $1.70 to $1.80 per Mcfe. Combined LOE, G&A and production taxes should be in the range of $1.35 to $1.60. At our Gathering business, we expect revenues will fall within the range of $90 million to $110 million. Operating expenses and depreciation will increase as a result of the capital spending we have planned in 2014 and '15, but earnings should grow meaningfully. Pipeline and Storage revenues are expected to be within the range of $270 million to $280 million, which is relatively flat compared to fiscal '14, but remember that fiscal '14 revenues were unusually high because of the cold winter. Looking beyond fiscal '15, we expect substantial growth in this segment as our larger expansion projects come online. At the utility, we're forecasting normal weather. And you'll recall that colder-than-normal weather added about $0.06 per share to earnings for fiscal '14. In addition, we're forecasting an incremental $7 million of an O&M expense related to the implementation of a new customer billing system. Turning to capital spending. Our overall capital budget is unchanged at $1.1 billion to $1.3 billion, but there were a few changes at the individual segment level. Our spending plans in the E&P segment are down $50 million from the previous forecast, while our Midstream businesses have increased their budgets by $50 million, largely because of the timing of spending between fiscal years on some of our larger expansion projects. Matt will have additional details on Seneca's budget later in the call, and all of our current guidance ranges can be found in our new IR deck. With respect to financing, our current forecast has us outspending cash flows in 2015 by about $425 million. The increase from our previous guidance is mostly due to the reduction in cash from operations caused by the drop in commodity prices. At this point, we're planning on a long-term debt issuance in the neighborhood of $500 million sometime in the spring or summer of 2015. Lastly, with respect to our hedging program, when you combine our firm sales and financial hedges at the midpoint of our guidance, we have pricing certainty with respect to about 60% of our natural gas production for fiscal '15, which is right in the middle of our policy range. Looking to fiscal '16 and beyond, we've begun to hedge the firm sales commitments associated with our capacity on the Northern Access 2015 Project. This past quarter, we did our first Dawn-based financial hedges, adding over 13.5 Bcf of new positions at an average price of $4.23 per MMBtu. We're encouraged by the liquidity in that market and expect to execute additional Dawn-based trades in the quarters to come. With that, I'll close and turn the call over to Matt.

Thanks, Dave. Good morning, everyone. Seneca had another strong quarter of production growth despite over 5 Bcf of price-related curtailments. Production grew 38% versus last year's fourth quarter and 33% for the full year. In California, production was 909,000 barrels equivalent for the quarter, up 7% versus last year. Continued success at South Midway Sunset and East Coalinga were the primary contributors to our growth. As you're all aware, oil prices have fallen by $20 since July. However, it's important to understand that even at an $85 oil price, our drilling program at East Coalinga has an IRR of greater than 30%, and at Midway Sunset, it is greater than 50%. Oil would need to fall below $60 before it would impact our California activity. In the Marcellus, we brought on 31 new development wells in the quarter, the most we've added in a single quarter since our Marcellus development began. And for the first time, Seneca's total production averaged over 0.5 billion cubic feet per day. New wells in our Western development area continued to perform right in line with expectations. We have 19 wells producing in the Clermont area with an average IP of 8.1 million cubic feet per day and an average EUR of 7.1 Bcf. As we extend our lateral length and refine our completion design, I expect our EURs in this area to exceed 8 Bcf. Regarding completion design, our goal remains to find the best bang for the buck that optimizes the completion while lowering the well cost. On the last call, I spoke about well spacing, and early indications suggest we'll be able to tighten our WDA spacing from 800 feet to 650 feet, which would result in hundreds of additional locations across our Tier 1 acreage. In addition, we recently completed several long lateral wells using a combination of sliding sleeves and plug-and-perf techniques with stage spacing of 190 feet as compared to our standard 150-foot design. If test results are favorable, the use of sliding sleeves and moving to wider stage spacing have the potential to significantly reduce our overall completion costs, particularly on long lateral wells. Finally, we continue to evaluate the importance of proppant concentration. Our standard Marcellus design has been approximately 1,400 pounds of sand per foot the last couple of years. More recently, we have experimented with higher sand concentrations, including 2 wells just completed in our hemlock area: 1 with 2,100 pounds per foot; and the other with 2,800 pounds per foot. We will closely analyze the results of these wells with an eye towards identifying the ideal mix of stage spacing and sand concentration. We're still in the first inning of WDA development, and what we learn and apply from these types of tests will significantly enhance the returns of our multi-decade drilling inventory. In the Utica and Pt. Pleasant play, we have evaluated logs and core from our vertical pilot well, Tract 007 in Tioga County and are pleased with the apparent rock quality and reservoir thickness. We plan to frac the horizontal well in December, and I hope to have well test results by our next earnings call. You may recall that this well is in relatively close proximity to the Utica wells that Shell announced a few months ago that had tested rates of 11 million cubic feet per day and 26 million cubic feet per day. We will likely drill our next Utica test next fall. Moving on to East Division gas marketing. Seneca has 96 Bcf of firm sales contracted for fiscal 2015; 92 Bcf of natural gas hedges in place; and an additional 16 Bcf of fixed price sales. Combined, these contracts provide 108 Bcf of fiscal 2015 production that is essentially locked in at an average price of approximately $3.70. At the midpoint of guidance, this volume is approximately 60% of our projected net gas sales for the fiscal year. That leaves 66 Bcf of our natural gas production at the midpoint of guidance, fully exposed to local pricing and basis differentials. As I mentioned, we've been curtailing production when prices fall too low. So far, this has resulted in approximately 4 Bcf of net curtailments since the fiscal year began 5 weeks ago. As we plan for the remaining 11 months of fiscal 2015, some further curtailments are likely depending on demand. Also in response to local pricing, we are limiting our completion plans to a single frac crew and reducing our CapEx guidance by $50 million. We still plan to drill 70 to 75 Marcellus wells in fiscal '15, but we'll only complete about 50 to 55. However, even with curtailments and a slowdown in completions, we are reiterating our production guidance of 180 to 220 Bcfe, a 25% increase over fiscal 2014 at the midpoint of the range. With minimal additional curtailments, I would anticipate fiscal '15 production in the top half of that range. With 15 to 25 Bcf of price-related curtailments, we will likely be in the bottom half of that range. For reference, we curtailed a total of 8 Bcf in fiscal 2014. Regarding year-end reserves, as of September 30, 2014, Seneca's total proved reserves were over 1.9 trillion cubic feet equivalent. We replaced 327% of production at a finding and development cost of $1.15. Marcellus F&D was about $1. It's important to note that Seneca maintains a conservative reserves booking policy. 73% of our total proved reserves are in the proved developed category. In conclusion, while Seneca faces some short-term pricing challenges, we have a coordinated marketing and operation strategy that will minimize our exposure to Marcellus basis differentials. We have firm sales in place for the majority of our fiscal 2015 production and significant firm transportation coming in fiscal '16 and '17. Most importantly, our development program is on track, and results continue to support our long-term growth plan. Operator, let's open up the line for questions.

[Operator Instructions] The first question comes from Chris Sighinolfi of Jefferies.

I guess, first, talking about the commodity price environment, never easy to cut things down guidance wise, the way you have, but appreciate you doing it. Curious with the $2.50 to $2.75 sort of spot guidance for Marcellus next year, Dave's earlier comments about the volatility in spot pricing you've realized just within the last week and then the 4 Bcf curtailments this quarter. I'm just wondering how we think about broadly where you draw the line. I think in the past you'd said somewhere in the $2.60, $2.70 range for curtailments, but I'm wondering how we think about that now.

Yes, Chris, it's lower than that. I'm hesitant to get real specific about the price. But if you think about the impact to earnings of an additional Mcf of production, and you think about our DD&A where it is today, and our relatively low variable LOE, those factors go into our decision about at what price do we curtail.

Okay. Okay, understood. And then I guess circling back on the prepared remarks, Ron, that you made about alternative forms of potential financing and thinking about Dave's updated forecast for outspend this year. I'm just curious if the timetable at all has shifted in terms of when you and the board might have to seriously consider that. I think last quarter -- if I understood you correctly, it was mostly tied with FID decisions on some of the large CapEx projects that may come to bear in '16. But just wondering with lower commodity prices and modestly reduced cash flow if that timetable changes at all.

Not tremendously, Chris. We've always talked, and we haven't updated everyone on our overall borrowing capacity. But suffice it to say that we've got lines of credit -- committed lines of credit that could even get us through probably the entire fiscal year next year, pretty close to it, without having to do a financing. So no, it's not. There's no increased pressure, but again, we are seriously looking at it, so it's just depending on getting the structure right and really getting the story very transparent about what our growth plans can be. And a lot of that depends on how quickly we can get capacity signed up on newer projects that we haven't even really talked about yet.

Okay. And I guess dovetailing on that last point, Ron, when you think about work that the Midstream business might be doing for third parties. What's the -- if the commodity situation in the Northeast shaped those conversations at all as of late or anything you can offer sort of on that front?

Yes. I mean, actually, it's -- when you talk about shaping conversations, it's toned them down substantially. With -- most of that activity up in the dry gas area, the activity has slowed down quite a bit. So it continues to be tough to try to get any other producers in that area signed up for new capacity on the Midstream side.

The next question comes from Becca Followill from U.S. Capital Advisors.

Can you talk a little bit about the impact of reducing the number of completions in '15 to 50 to 55 wells? What impact that would have on 2016 production?

Becca, it's not going to have a huge impact on '16 production. Obviously, that delay in the completion timing makes a difference. But we're still anticipating significant double-digit growth into '16.

A minimal impact. And then on the hemlock wells that you talked about, where you've increased the proppant density, there is -- can you just remind me again, where those stand when you've completed them? How long have they been online? Any preliminary results?

They're not online yet, Becca. We're actually fracking them as we speak.

The next question comes from Timm Schneider of Evercore ISI.

Evercore ISI. Just a quick question on the timing of the MLP, the Midstream one. Is that something the structure that you would have to have in place before all this CapEx gets spent? Or is that something that could come during that phase or after, and then you have some flexibility with funding at the NFG level or potentially at the MLP?

Well, I guess you really covered that whole gamut there, Timm, and I -- I mean, we -- there could be some flexibility. But I mean, as we've said, we view the MLP as a financing tool. And so it really depends on kind of where we stand, and obviously, we're mindful of the market. We're mindful of the market that has had a good reception for some of the recent MLPs. But since we look at it over the long term, and are looking at it as a sustainable way to finance for our growth for the long term, we're -- we don't feel constrained to jump out there right away. So there is some flexibility over the next year.

Got it. In terms of I guess using a baseball analogy, what inning are you guys internally in kind of thinking about this? Is this just kind of conceptual stages? Or have you actually talked to some outside advisers on these?

Oh, well, no. We're -- it's much past the conceptual stage. I mean, we're actually looking at -- we're a lot farther down the road. Let's leave it at that.

The next question comes from Carl Kirst of BMO Capital.

Just a couple of timing questions, if I could. And Matt, you'd kind of talked in your prepared comments about the potential for going to the tighter spacing, as well as potentially seeing the reduction in the completion costs with the longer laterals. And I was wondering if you had a sense of timing as to when that would sort of be a firm decision that yes, this is going to be sort of the spacing we're now going to embark on, and we can kind of sort of put those additional Tier 1 wells into the backlog with certainty. Just trying to kind of get a better sense of when that inflection point might be.

Sure, Carl. I guess what I would say is that we are already at the point of making our standard spacing between wells 650 feet. So in that sense, that adds wells to the overall inventory. So all other the things being equal, that could add, like I said hundreds of wells to the Tier 1 inventory. Recognizing that, that balance is with longer lateral, so longer laterals actually reduce inventory, but obviously don't decrease the total amount of recoverable reserves or frac stages.

Right.

And with respect to utilizing the sleeves you were referring to. I mean, is that something where you've already kind of made a decision that, that's sort of the optimal completion? And if so, is there sort of an updated well cost number? I know you said significant, but I didn't know if there was any further color you could add on that.

Yes, Carl, I guess the way you need to think about it is the sliding sleeves -- one of the primary drivers for the sliding sleeves is it allows us to complete longer laterals more easily. So you use the sliding sleeves in the -- in sort of the toe stages of the well. But what I also mentioned in that same sentence is that we're experimenting with wider stage spacing. So we've gone to 150-foot stage spacing what we referred to as our reduced cluster spacing. If we can pump more sand on a wider stage spacing, ultimately, we'll spend a little more on sand, but we'll -- by doing fewer stages, we'll spend less money overall in the well, and may, in fact, actually have a better well than we had with the tighter spacing and less sand. Now the -- those kind of decisions as to what our standard is are still -- remain to be determined based on the results we see on these wells that we're fracking kind of as we speak and have fracked but haven't put online yet.

Okay. And that would probably lead to that optimal completion as far as using the wider stages presumably that, that can also change from sort of region to region, is that fair? Or is that something that you think will have -- will hold over a wider area?

No, that's fair. I think the way to think about it, Carl, if as we grow this WDA development, we'll kind of constantly evolve what our standard completion design is, recognizing that there may be reasons to modify it as we move into different areas.

Okay. No, that's very helpful. And then one maybe last, again, probably more sort of timing question. If the actual well test at Tract 007 works out, and I guess you indicated there'd be another test perhaps in another well in the fall. If you get very encouraging results but recognizing that it's more in the EDA, is that something that basically potentially builds a backlog or -- potential backlog of inventory, but maybe we should still think about that in the post Sunrise 2018 type of time frame? Or is there an opportunity that if you get just a 26 million cubic feet a day well, that, that something can be shifted to allow for that development?

Yes. I mean, there's so many moving parts in that question, Carl. It depends on what we're seeing in the markets if we found a year from now that basis differentials on Tennessee 300 were substantially better, we might consider bringing a fourth rig in and adding a lot of wells in the Tioga County drilling the Utica. But that's all subject to what we see in the well and what we see in the market.

The next question comes from Tim Winter of Gabelli & Co.

I was wondering if you could talk a bit more about the Northern Access pipelines in the process. Who is taking the capacity or the output? And are there any specific or major obstacles in getting these permitted and completed?

; Well, okay, Tim. I'll talk about the -- operationally the construction and stuff. The Northern Access 2015 is moving right along. We expect to have the FERC certificate sometime this month, if everything goes according to schedule. There have been no major SNAFUs or hiccups that we've encountered along the way. Seneca was taking all that capacity, and I'll let Matt talk about the contracts that we already have for that production moving through that space.

Yes. So we have that production sold on long-term contracts at a Dawn-index price. So that's $150 million a day -- I'm sorry, it's $140 million a day.

Yes. So that's all said with respect to Northern Access 2016, as I mentioned, we're still in the FERC prefiling stage, and all the environmental work and land work seems to be going along just fine. And we expect to be making the formal full FERC filing in the first quarter of 2015. That would put us on schedule to have gas flowing there or to start construction in January of 2016. And the current target is to have gas flowing in November of 2016, which is our 2017 fiscal year. With respect to that market, it's a little bit tough to get that far ahead of ourselves to get -- actually get a buyer for those volumes just now because there's not even a pipeline built. So it's premature to try to get anything really locked in at this point.

I would now like to turn the call over to Brian Welsch for closing remarks.

Thank you, Cathy. 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, November 14, 2014. 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 40197121. This concludes our conference call for today. Thank you, and goodbye.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.