National Fuel Gas Company (NFG) Q4 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2013 National Fuel Gas Company Earnings Conference Call. My name is Dave, I'll be your operator for today. [Operator Instructions] As a reminder, the call is being recorded for replay purposes. I'd now like to turn the call over to Mr. Tim Silverstein, Director of Investor Relations. Please proceed, sir.

Thank you, Dave, and good morning. We appreciate you joining us on today's conference call for a discussion of last evening's earnings release. With us on the call from National Fuel Gas Company are Ron Tanski, President and Chief Executive Officer; Dave Bauer, Treasurer and Principal Financial Officer; and Matt Cabell, President of Seneca Resources Corporation. At the end of the prepared remarks, we will open the discussion to questions. This morning we posted a new slide deck to our Investor Relations website. We may refer to it during today's call. We would like to remind you that today's teleconference will contain forward-looking statements. While National Fuel's expectations, beliefs and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last evening's earnings release for a listing of certain specific risk factors. I would also like to mention that our Analyst Day in New York City is Tuesday, November 19. If you are a member of the investment community and would like to attend but have not yet registered, please contact me directly. For those of you attending, we look forward to seeing you at the event. With that, we will begin with Ron Tanski.

Thanks, Tim, and good morning, everyone. Our fourth quarter topped off a really good fiscal year. Our year-over-year earnings improved in each of our reporting segments, but it was our upstream and midstream businesses that led the way. Our operating results for the year of $3.14 per share, are only $0.03 shy of our record operating results of $3.17 per share that we achieved in fiscal 2008. Given that our realized price for our natural gas production in 2008 was $9.05 per Mcf compared to the $4.10 per MCF that we realized for our production this year, I'd say our team did a great job. While we had good financial results for fiscal 2013, I'm particularly happy with our operational results. At Seneca Resources, production for the year, at 120.7 billion cubic feet equivalent, was 45% higher than last year. During the fourth quarter, Seneca's average daily natural gas production was over 314 million cubic feet per day and oil production averaged approximately 7,800 barrels per day. In addition to increasing its production, Seneca also increased its proven reserve base by 24% to a total of 1.5 trillion cubic feet equivalent. More importantly, we've had some great exploration results in our Western development area that give us plenty of running room in our Exploration and Production segment for the foreseeable future. As production in the Marcellus continues to grow, our midstream pipeline companies continue to design and build the compressors and pipelines to get that production to market. Projects like our Northern Access and Line N pipelines, that were placed into service at the beginning of the fiscal year, helped to drive the 32% increase in year-over-year operating results in the Pipeline and Storage segment. Our engineering and marketing teams are continuously looking at new opportunities to grow this segment. In order to give you an appreciation of the activities surrounding the buildout of our gathering systems to accommodate Seneca's production, last night's release shows operating results for our Gathering segment. While this segment is currently concentrating on project to get Seneca's production to market, we have also been discussing potential projects with third-party producers. We expect that our investment in this segment will grow in parallel with Seneca's continued growing production in the Western development area. Clearly, the increasing production volumes by all producers in the Marcellus is putting a strain on the pipeline infrastructure in the basin, either by way of capacity constraints or basis pricing issues. We see this as an opportunity to build additional pipeline projects that can provide some market optionality for producers in the area. At our Analyst Day in a couple of weeks, we expect to go into more detail about our strategy to address both takeaway capacity and basis pricing. Those issues, in particular, keep us focused on a realistic growth plan that allows us to increase production next year by 20% to 35%, but with only a modest outspending of our cash flow. Our drilling success in the Western development area continues to delineate growth opportunities that will allow us to ramp up our drilling when we get some clarity on commodity pricing a few years out or have the ability to hedge prices that lock in our economics. We'll also discuss our strategy on those fronts in more detail at our Analyst Day. We had a great year. And as you saw from our earnings guidance in last evening's release, we project that next year will be even better. Now I will turn the call over to Matt Cabell to discuss some more detail regarding Seneca's operations.

Thanks, Ron, and good morning, everyone. Seneca had another good quarter to top off an outstanding fiscal year. Production was up 35% quarter-over-quarter and 45% year-over-year. We replaced 351% of production in fiscal '13 at a cost of $1.31 per Mcfe. Marcellus Shale F&D was $0.99 per Mcfe and year-end proved reserves were 1.55 trillion cubic feet equivalent, 71% of which is developed. In California, oil production was up versus last year's fourth quarter while gas production was down due to third-party gas pipeline takeaway issues affecting our CESP field. Overall, California production was flat with fourth quarter 2012 and down 2% for the full fiscal year. At Coalinga, we've increased gross production to 530 barrels of oil per day as we brought on 8 new producing wells and reactivated half of the idle legacy wells. 4 additional new producers will come online this quarter. Initial core results from the new wells we drilled at Coalinga confirm a significant volume of oil in the reservoir. So far, this farm-in project is working well for us and we expect to continue to grow Coalinga production in 2014. Also in California, our South Lost Hills horizontal Monterey Shale well is producing 35 barrels of oil per day and 1.1 million cubic feet of gas. Our estimated ultimate recovery for this well is 2.7 Bcfe, a little better than anticipated. However, the oil cut is lower than expected which drives the rate of return down to the 10% to 15% range. We have 2 additional South Lost Hills horizontals planned for fiscal 2014 which will test different intervals in the Monterey in a different part of the South Lost Hills structure where we anticipate a higher oil cut. Moving on to the Marcellus. We brought on new 5-well pad, Pad E, at Tract 100. 3 of these 5 wells IP-ed at over 20 million cubic feet per day and even the weakest of the 5 peaked at nearly 15 million. This winter, we will add Pad M, a 6-well pad that includes 5 Marcellus wells and 1 well in the Upper Devonian Genesee followed by the 7-well Pad R. And by midsummer, we should see production from the 10-well Pad T. So 23 additional Tract 100 wells coming on in fiscal 2014. Over the past 12 months, we've added approximately 4,700 acres to our position in the area around Tract 100 and Gamble Township in Lycoming County. We have a total of 100 to 120 locations in the area with 30 wells producing, 20 drilled but not yet completed, another 50 remaining to be drilled on existing leasehold and 20 more with only minimal additional leasing. We expect to be active in this area through mid-2016, assuming we keep 1 rig in the area. Moving on to our delineation drilling in the Western development area. We tested 2 new wet gas wells at Owl's Nest with peak 24-hour rates of 6.1 million cubic feet per day and 3.4 million. The lower-rate well had a shorter lateral and tested a few modifications to our frac design. The better well, with a 6.1 million IP and 6,100-foot lateral, is more representative of our expectations for the area. We have one more delineation test in the queue, a wet gas well at Tianesta. We are commissioning the condensate-handling facilities for this pad and expect to float sales by the end of the month. 3 of our fiscal 2013 WDA delineation wells have now been producing long enough to estimate EURs. The previously disclosed Rich Valley well has an estimated ultimate recovery of 7.4 Bcf. The Clermont 9H, which was frac-ed using a reduced cluster spacing design, has an EUR of 8.6 Bcf. And the Clermont 10H, which did not use RCS, has an EUR of 6.6 Bcf. At our Analyst Day on November 19, we will be discussing EUR ranges across a broad swath of our WDA acreage. Our Clermont development is now underway, as we are currently drilling the fifth well on a 9-well pad. While our fiscal '14 plans are somewhat flexible, our current rig schedule is essentially one rig at Clermont, one in Lycoming County and one rig sharing time between Tract 595 and delineation drilling in the WDA. As we plan our development of the WDA, we are working with our midstream company to build a significant new gathering system, with capacity of approximately 1 Bcf per day. By August 2014, we expect to deliver production into TGP 300 from our first development pad. And by year-end, we expect to have 15 wells producing on the system. We are also working on several long-term transportation projects that will deliver our gas to multiple markets, targeting a basis significantly better than delivery in the basin. We will provide more detailed information when binding agreements are executed. In the somewhat challenging gas price environment, we all recognize the importance of successfully executing our plan with efficient and effective operations. The latest DEP data showed that Seneca is a leading operator in the counties where we are most active. In Lycoming County, Seneca's average production per well over the last the DEP reporting period was nearly double that of the second best performer. And in Tioga County, we were essentially tied for the top spot. When the next 6 months of data come out, I expect our Elk County results will be 3x or 4x the next best competitor. We have also made good progress this year on reducing the cost of horizontal wells through faster rig boost, supply chain initiatives and optimized drilling techniques that cut our spud to Td time by about 5 days to an average of 14.8 for the recently completed quarter. At Tract 100, our drilling cost has dropped from an average of $4.1 million in fiscal 2012 to $2.5 million in the fourth quarter of 2013. We also recently signed a new pressure pumping contract that will reduce our frac-ing cost by $13,000 per stage or about $0.5 million for a typical RCS completion. We these improvements, we expect to drill and complete 5,500-foot laterals with 37 stages for approximately $7 million. Our operational improvements are also leading to an increased annual well count. Although we plan to hold our rig count flat at 3, we expect to drill and complete 55 wells in fiscal '14 as compared to 42 completed in fiscal '13. Despite this 30% increase in activity, our drilling and completion budget will only increase by 15% from '13 to '14. Moving on to the Utica Shale. We tested our Mount Jewett well at a 24-hour peak rate of 8.5 million a day and a 7-day rate of -- average of 6.8 million a day. This well is an important data point for us. The Utica/Pt. Pleasant section is thick here, approximately 300 feet, and we calculate high gas in place of approximately 120 Bcfe per 640-acre section. The next step is to get some long-term production history, and we are producing the sales now. Further delineation is planned for late 2014 or early 2015. Let me conclude by saying that fiscal 2013 was a great year for Seneca. Not only did we increase production by 45% and add reserves for $1.31 in Mcfe, we also made a major breakthrough on our legacy WDA acreage position. We will go into detail about what we have learned at our Analyst Day meeting on November 19. But the takeaway for now -- we have identified, a high-quality geologic trend with up to 2,000 well locations in Elk and Cameron Counties or about 10 to 12 trillion cubic feet equivalent of resource potential. With this inventory, we expect to have years or, possibly, decades of continued growth. Now I'll turn it over to Dave.

Thank you, Matt, and good morning, everyone. As Ron said, the fourth quarter capped another great fiscal year for National Fuel. Yesterday's release does a good job explaining the major variances in earnings for the quarter. So I won't repeat them again here. The only unusual item in the quarter was the charge we recorded in connection with our utilities rate proceeding in New York. Confidential settlement negotiations with parties to the case are ongoing and, therefore, we really can't say anything more about it. However, we are making progress and hope to reach a settlement in the near future. Excluding that charge, earnings for the fiscal year were $3.14, a bit higher than the high end of the range of our $3 to $3.10 guidance for the year. 2 factors contributed to that outperformance. First, at the Utility, our September 30 accounts receivable aging was better than we had expected, so we were able to reverse about $5 million of the bad debt expense we had recorded earlier in the year. And you should note that there was a similar size adjustment to bad debts in last year's fourth quarter, which is why this item doesn't appear as an earnings variance in yesterday's release. Second, our effective income tax rate for the quarter of 37% was about 400 basis points lower than the rate we expected for the quarter. And as you can imagine, there are a lot of moving parts in our tax calculations. And most of the difference is attributable to the timing with which certain items were reflected across the fiscal year. Looking forward, we still expect our 2014 effective tax rate will be in the range of 40% to 41%. As you noted in last night's release, we made a change to our segment reporting. The operations of our NFG Midstream subsidiary, which owns and operates the non-regulated Covington and Trout Run Gathering Systems, are now reported in the new Gathering segment. Previously, the Gathering segment's reserve -- results were recorded in All Other. We made this change to highlight the growth we have experienced in this business. As you can see in the segment income statements, the Gathering segment's earnings have increased significantly and we expect that trend to continue in lockstep with Seneca's production. Switching to next year's guidance, we're increasing our fiscal 2014 earnings expectations to a range of $3.10 to $3.40 per share, at the midpoint, a $0.075 per share increase. The new range reflects a few significant items. First, it assumes Seneca's updated production guidance of 145 Bcfe to 165 Bcfe, at the midpoint, a 15 Bcfe increase over the previous guidance. In addition to benefiting Seneca's earnings, this production increase will also have a meaningful impact on NFG Midstream's gathering business. Second, it assumes about $5 million less of pension and post retirement benefit expense across the system. This was caused by a variety of factors, including a higher-than-projected discount rate and better-than-projected asset returns in the fourth quarter. Lastly, going in the other direction, we're updating our Marcellus pricing basis assumptions to reflect more current market conditions. In particular, we're now assuming Dominion South Point will trade at a $0.30 to $0.40 discount to NYMEX. Our previous guidance had been minus $0.10 to minus $0.20. This change will impact our realized pricing on our Dominion-based firm sales contracts and on our Dominion-based hedges. And you should note that our hedge positions listed in the back of the earnings release are now broken out by pricing point. In addition, for our approximately 25 Bcf of Eastern development area production that's not subject to firm sales agreements, we're assuming an average discount to NYMEX of minus $0.75 per Mcf. And previously, our assumption had been minus $0.25. Obviously, pricing basis in the Marcellus has been volatile. And it's our hope that the recent expansion projects in the region will alleviate some of the weakness in the market. We're starting to see the initial impacts of that new capacity this week as basis has tightened up a bit. But for now, we're being conservative and we'll revisit these assumptions as we move through the fiscal year. With regard to Seneca's expenses, our guidance for DD&A, LOE and other taxes is unchanged. We're updating our G&A expense guidance to a range of $0.40 to $0.45 per Mcf. And this change is attributable solely to our increased production guidance. Our G&A expense assumption in nominal dollars is not changed. With regard to capital spending, our updated consolidated capital budget for 2014 is a range of $845 million to $1.025 billion, at the midpoint, a $70 million increase from our previous guidance. Most of that increase is attributable to the timing of spending on projects in our midstream businesses. The Pipeline and Storage budget is now $115 million to $135 million. And the Gathering segment is $100 million to $150 million. Seneca's and the Utility's budgets are unchanged at $550 million to $650 million for Seneca and $80 million to $90 million for the Utility. At the midpoint of our earnings and capital spending guidance, we expect capital spending will exceed our cash from operations by about $100 million, that's up from the $25 million to $50 million outspend we forecast in August. The increase is attributable to 2 main factors. The first is the expected higher spending in our midstream businesses that I just mentioned. The second is income taxes because of a variety of factors, including the growth in Seneca's and our midstream company's revenues, combined with the expected elimination of bonus depreciation, we now project paying approximately $40 million in alternative minimum tax in fiscal '14. When you add that $100 million outspend with our expected $125 million of dividend in 2014, our projected financing needs are now in the area of $225 million, part of that will be met with cash from the balance sheet. We exited the year with $65 million of cash on hand, in part, with short-term borrowings. We don't have any long-term debt maturities in fiscal '14. Lastly, we were very active with our hedging program this past quarter, adding 27.5 Bcf of new natural gas positions for fiscal '14. In total, we have just over 91 Bcf of gas hedged at an average price of $4.25 per Mcf and just under 2 million barrels of oil hedged at an average price of $100 a barrel. At the midpoint of our production guidance, those hedged positions equate to 2/3 of our forecast production for both gas and oil, which is right in line with our hedging policy. Our policy allows us to be as much as 80% hedged. So if we see any spikes in pricing, we'll likely add positions. With that, I'll close and ask the operator to open the line for questions.

[Operator Instructions] This comes from Stephen Maresa at Morgan Stanley.

I just -- I had 2 questions, one on the MP and one on midstream. Just on the MP front, just wanted to drill a bit more into what is driving the continued higher production forecast at Seneca. And maybe you can discuss just exactly where you've been the most positively surprised. What do you think is the potential for your wells to continue to surpass guidance expectations? And as a subset to that, you talked a little bit about your views on basis, how much more takeaway capacity do you think you need to continue to grow at this pace at Seneca?

Stephen, there are a lot of questions in there. I guess I'll start with how we're increasing our production guidance. I would say there are really 3 things. One, our view of the base production decline has changed some. So our assumption for that rate of decline is not as steep as it had been. Secondly, these Lycoming County wells -- well, I guess, we're to the point where they're not surprising to us anymore. We're actually starting to forecast them at rates that are similar to how they've actually been performing. It was kind of tough to do that when they've been coming in at such high rates. And I guess the third is our operational efficiencies are allowing us to get more wells online in a given time period than we had previously. With regard to takeaway capacity, when we think about takeaway capacity in terms of, say, firm transportation projects, we're thinking very long-term here. So the projects we're looking at that would get us to some other markets are -- they're over a spread of years from shorter-term projects that are just maybe 1 year to 1.5 years away to things that don't start until 2017 or later. But it's a big number.

Okay. And then just moving to midstream, with it continuing to become more of a meaningful part of the company, given your well locations and third-party opportunities and a little bit of outspending now -- 2 questions on this. One, how receptive are you seeing third-party customers using NFG Midstream, what's the view of even maybe overall CapEx opportunity? And then what prevents you from creating an MLP vehicle sooner rather than later to help compete in this arena?

Steve, with respect to the third-party production, and as we had laid out before, and then you can see the maps in the materials that we filed, most of the acreage for -- with the third-party drilling or third-party potential is in the dry gas window. And as you know, people had shied away from drilling in that window, favoring the more liquids-rich areas to the Southwest and even in the Utica. So while we have had discussions, it's been tough to get anyone to sign some actual contracts for takeaway capacity because they've just moved rigs out of the dry gas window. Given that, and looking at our cash flow, as Dave mentioned, we only see a modest outspend right now. And as I mentioned on the last quarter's call, we're going to need to move into larger capital needs before we look to an MLP for growth capital there. And we're just comfortable with our spending now given the fuzziness on the horizon, of basis and commodity pricing.

And your next question comes from the line of Carl Kirst at BMO Capital.

This is Danilo, filling in for Carl. I just wanted to go back a little bit to the Marcellus production. If you're sort of seeing takeaway capacity, a strong takeaway capacity in 2017 timeframe, how confident then are you in the guidance for next year? I mean, are you still seeing that that's -- do you have high conviction that you're going to achieve that guidance range?

Danilo, are you asking about the breach in the 145 Bcfe to 165 Bcfe that we have in our guidance?

Exactly, in light of the basis issues that you sort of spoke about and takeaway capacity issues as well.

Yes. I guess the way to look at it is, our existing firm sales get us in the range of 125, 130 Bcf. If we curtailed all of our spot sales, we'd still be in that kind of a range. And today, we're not curtailed at all because the spot basis is acceptable. I think there's still some uncertainty to it. But we feel pretty confident that with the new projects that have come online, at least through the winter months, we should be able to produce at our full capacity. And likely through the entire year, most of the time, we'll be able to produce at full capacity.

Okay. And I guess moving on to the Utica. Are the next data points there going to be available? You said, I think, late fiscal '14 and early '15 or is there something that we can expect sooner?

No. In fact, I wouldn't even expect it late '14. I think what I said was we plan to drill additional wells in late '14 to early '15. We want to get some more production history from the existing 2 wells and sort of think through what we want to do next. So if we were to spot a well, say, fourth quarter of '14, by the time we've got it drilled, frac-ed and tested, we're looking at sometime in '15.

Okay, got you. And I guess my last question is on the LDC. Obviously, you can't speak a lot about the rate proceedings there, but are you expecting significant headwinds or what is the status update on that front?

Danilo, this is Dave. There's really not a lot we can say. We're literally in settlement discussions today. So I wouldn't want to comment too much on that.

Your next question comes from the line of Becca Followill at U.S. Capital Advisors.

On the comments, Matt, on maybe 2,000 I think it was, potential locations in Elk and Cameron County, at what prices do you need to make those economic?

It varies, but the cutoff for what we're using to count those well locations is $4. $4 realized pricing.

$4 realized, okay.

So it's going to vary from, say, sort of the low to mid $3 up to -- pushing close to $4.

And you'll get some more detail on that in the Analyst Day presentation.

Great. And then, what are you assuming for California oil differentials in your guidance?

Becca, I think, the best way to look at it would be Brent -- say, 90% of Brent is generally how we [indiscernible].

Okay. You're assuming roughly that's the basis differentials that we're seeing now?

Yes. I think that's right.

Okay. And then, Matt, you also commented that the base decline -- a further reason for the higher production guidance was a lower base decline that you're seeing. Any idea of whether or not you guys might update some of your estimates of ultimate recovery at this upcoming analyst meeting as a result of the lower base declines?

We tend to update them every time we do a new slide deck and there's a table in there that shows EURs at Covington, 595 and Tract 100. And that EUR number, it's -- it may not look like a big change to you if you look at it, but it has changed for all -- I think, for all 3 of those areas over the course of the last 12 months or so. I couldn't tell you for sure whether you'll see a change between now and Analyst Day or not.

So that shows up in the November presentation that you posted.

It should, yes.

The next question comes from the line of Timm Schneider at ISI.

Can you do me a favor and maybe reconcile that net wellhead price that Becca just asked about, to what else do I need to add in there in terms of kind of gathering and transport cost basis, to kind of get to NYMEX equivalent?

So you mean for that $4 and lower pricing of the...

Yes, exactly. The potential.

Well, I guess, part of the reason we're doing it on realized pricing is it gives you the ability to use your own assumption for basis differentials. I guess, what I'd tell you is, right now, we're seeing Dominion South Point in the -- what do we say? $0.30 to $0.40 range. So that gives you some sense of what to expect. That's probably about all the information we're ready to disclose.

Yes. Tim, I think I'd add to that, that gathering would already be reflected in the economics. So the $4, you'd only have to consider basis to NYMEX, not any gathering charges.

Got it. What about long-haul transporting, if you're in the pipeline, is that -- do you guys throw it in under gathering?

Well, I guess it depends how you look at it. If we were to take transportation ourselves, you'd have to consider that as part of the basis. Or if we use firm sales, obviously, we'd be doing it at, likely at a discount.

Got it. And then just real quick on the East, that's $0.75 basis assumption, are most of your volumes being priced off Leidy or are they going anywhere else?

The majority would be essentially Leidy pricing, yes.

Thank you. There are no further questions for you. So I'd now like to turn the call back to Mr. Tim Silverstein for closing remarks.

Thank you, Dave. 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 2:00 p.m. Eastern Time on both our website and by telephone and will run through the close of business on Friday, November 15, 2013. To access the replay online, visit our Investor Relations website at investor.nationalfuelgas.com. And to access by telephone, call 1 (888) 286-8010 and enter passcode 23666033. This concludes our conference call for today. Thank you and goodbye.

Thank you very much for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a good day and a great weekend.