National Fuel Gas Co (NFG) 2014 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Quarter Four 2014 National Fuel Gas Company earnings conference call. My name is Kathy 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, Kathy, and good morning. We appreciate you joining us on today's conference call for a discussion of last evenings 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 will 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 will 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 three 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 a 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 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 are 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 three rigs active even at the lower commodity prices that we are experiencing in the near term.

We had a great construction season for our gathering company. The trunk lines 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 are 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 are 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 are 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 are 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 are always careful with our spending, with the current dip in commodity pricing, we are 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 financing for us. Given the volatility that we've seen in the upstream MLP market and the ongoing 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 are still in the pre-filing 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 are still targeting January 2016 for the receipt of the 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 will 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 three 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 great 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 with 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 post-retirement benefit expenses. Higher bad debt expense also contributed to the decrease in earnings in 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 release, so I won't repeat them all here. Instead, I will focus on our guidance for fiscal 2015. As we said in last night's release, our new range for fiscal 2015 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 are 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 will impact earnings by about $0.05 per share.

We are also lowering our fiscal 2015 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 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 are 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 our earnings 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, but a little cold weather can make a big difference. Today we are selling production at over $3.40 an Mcf. This volatility will almost certainly continue and we will revise our pricing assumptions in the coming quarters if it's appropriate.

For fiscal 2015, 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 2015 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 2015, 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 2014, but remember the fiscal 2014 revenues were unusually high because of the cold winter.

Looking beyond fiscal 2015, we expect substantial growth in this segment as our larger expansion projects come online. At the Utility we are forecasting normal weather. You will recall that colder than normal weather added about $0.06 per share to earnings for fiscal 2014. In addition, we are forecasting an incremental $7 million of an O&M expense related to the implantation 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 are 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 2015, which is right in the middle of our policy range. Looking to fiscal 2016 and beyond, we have 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 are encouraged by the liquidity in that market and expect to execute additional Dawn-based trades in the quarters to come.

With that, I will 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 are all aware, oil prices have fallen by $20 since July; however, it is 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 have 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 continue 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 will be able to tighten our WDA spacing from 800 feet to 650 feet, which would result in hundreds of additional locations across our tier one 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 cost, 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 two wells just completed in our Hemlock area, one 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 are 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 Point Pleasant play, we have evaluated logs and core from our vertical pilot well at Track 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 test 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 have 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 five 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 2015, but will 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 2015 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 is 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 operations 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 2016 and 2017. 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) Chris Sighinolfi, Jefferies.

Good morning, guys. Thanks for the color this morning and for taking my question. I guess, first, talking about the commodity price environment, never easy to cut things down guidance-wise the way you have, but I appreciate you doing it.

Curious with the $2.50 to $2.75 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 curtailment 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.

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, understood. 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 am 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 2016. But just wondering, with lower commodity prices and modestly reduced cash flow, if that timetable changes at all.

Not tremendously, Chris. We have 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 or 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, I guess, dovetailing on that last point, Ron, when you think about work that the midstream business might be doing for third parties, what is the --? Has the commodity situation in the Northeast shaped those conversations at all as of late? Or anything you can offer sort of on that front.

Actually, when you talk about shaping conversations, it has 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.

Okay, great. Thanks for the time. I'll get back in the queue. Appreciate it.

Becca Followill, US Capital Advisors.

Good morning, guys. Can you talk a little bit about the impact of reducing the number of completions in 2015 to 50 to 55 wells, what impact that would have on 2016 production?

Becca, it's not going to have a huge impact on 2016 production. Obviously that delay in the completion timing makes a difference, but we are still anticipating significant double-digit growth into 2016.

Minimal impact, thank you. On the Hemlock wells that you talked about where you've increased the proppant density, those -- can you just remind me again where those stand? You've completed them; how long have they been online? Any preliminary results?

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

Okay, great. Thank you.

Timm Schneider, 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 the whole gamut there, Timm. There could be some flexibility but, as we have said, we view the MLP as a financing tool so it really depends on kind of where we stand. Obviously, we are mindful of the market.

We are mindful that the market 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 our growth for the long-term, we don't feel constrained to jump out there right away. So there is some flexibility over the next year.

In terms of, I guess using a baseball analogy, what inning are you guys in internally in thinking about this? Is this just conceptual stages or have you actually talked to some outside advisors on this?

No, it's much past the conceptual stage. We are actually looking at -- we are a lot farther down the road. Let's leave it at that.

Okay, got it. Thank you.

Carl Kirst, BMO Capital.

Thank you. Good morning, everybody. Just a couple of timing questions, if I could. Matt, you had kind of talked in your prepared comments about the potential for going to the tighter spacing, as well as potentially seeing a reduction in the completion costs with the longer laterals.

I was wondering if you had 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 are 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 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. All other things being equal, that could add, like I said, hundreds of wells to the Tier 1 inventory.

Recognizing that that balances with longer laterals. So longer laterals actually reduce the inventory, but obviously don't decrease total amount of recoverable reserves or frac stages.

Right. And with respect to utilizing the sleeves you were referring to, is that something where you've already kind of made the decision that that is 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 sleeve is it allows us to complete longer laterals more easily, so you use the sliding sleeves in sort of the toe stages of the well. What I also mentioned in that same sentence is that we are experimenting with wider stage spacing, so we had 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 will spend a little more on sand, but by doing fewer stages, we will spend less money overall on the well. And may, in fact, actually have a better well than we had with the tighter spacing and less sand. Now those kind of decisions as to what our standard is are still -- remain to be determined based on the results we see of these wells that we are fracking as we speak and have fracked but haven't put online yet.

And that would probably lead to that optimal completion as far as using the wider stages. Presumably that could 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?

That's fair. I think the way to think about it, Carl, is, as we grow this WDA development, we will 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.

That's very helpful, thank you. 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 would be another test perhaps or 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, potential backlog of inventory but maybe we should still think about that in the post-Sunrise 2018 type of timeframe? Or is there an opportunity that if you get just a 26 million cubic feet a day well that something can be shifted to allow for that development?

There's so many moving parts in that question, Carl. It depends on what we are 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 into Tioga County drilling the Utica. But that's all subject to what see in the well, what we see in the market.

Completely understand. I appreciate all the color, thank you.

Tim Winter, Gabelli & Company.

Good afternoon and thanks for taking my questions. I was wondering if you could talk a little bit more about the Northern Access pipelines and the process. Who is taking the capacity or the output? Are there any specific or major obstacles in getting these permitted and completed?

Okay, Tim, I will talk about operationally the construction and stuff. 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 have encountered along the way.

Seneca was taking all that capacity. And I will let Matt talk about the contracts that we already have for that production moving through that space.

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

Yes, so that's all set. Now with respect to Northern Access 2016, as I mentioned, we are still in the FERC prefiling stage and all the environmental work and land work seems to be going along just fine. 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 is a little bit tough to get that far ahead of ourselves to 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.

Thank you.

Thank you for your question. I would now like to turn the call over to Brian Welsch for closing remarks.

Thank you, Kathy. We would 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, November 14, 2014.

To access the replay online, please visit our Investor Relations website at investor. NationalFuelGas.com. 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.