National Fuel Gas Company
Q3 2013 Earnings Call Transcript

Published: 9 Aug 2013

[Operator:]

Good day, ladies and gentlemen, and welcome to the Third Quarter 2013 National Fuel Gas Company Earnings Conference Call. My name is Gwen, and I will be your operator for today. [Operator Instructions] I would now like to turn the call over to your host for today, Mr. Tim Silverstein. Please proceed.

[Timothy Silverstein:]

Thank you, Gwen, 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 Ronald 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. I would also like to let everyone know that we have an Analyst Day scheduled in New York City for the morning of Tuesday, November 19. If you're a member of the investment community and would like to attend and have not received a save-the-date, please contact me directly. 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, we will begin with Ron Tanski.

[Ronald J. Tanski:]

Thanks, Tim, and good morning, everyone. We've published a lot of information recently. With the combination of Seneca's operational update at the end of July, last evening's earnings release and the update of our Investor Relations slide deck, we believe we provided a fair amount of clarity on our future growth opportunities. Now we're going to switch up the order of our discussion this morning. Dave Bauer is going to provide some more color on our quarterly earnings details and give us a look at our preliminary 2014 forecast. And then Matt Cabell will discuss Seneca's results in more detail. Then I'll have a few more comments before we open up the line for questions. And here's Dave Bauer.

[David P. Bauer:]

Thanks, Ron, and good morning, everyone. Starting with our results for the quarter. As you saw in last night's release, we had another terrific quarter with earnings and EBITDA up in each of our major operating segments. Consolidated earnings of $0.69 per share were up by 1/3 compared to last year, and that's in spite the $0.06 per share income tax charge at Seneca. Consolidated EBITDA increased by more than 30%. Seneca had a really great quarter. Thanks to the impressive wells at Tract 100, production was up 54% compared to last year's quarter and, on a sequential basis, up 18% compared to the second quarter of this year. That production increase, combined with an increase in after hedging, oil and gas prices, was the primary driver behind the $0.12 per share or 45% increase in Seneca's earnings. On the expense side, per unit DD&A expense of $1.97 per Mcfe was down significantly from both last year and from the second quarter of this year. This was driven by a substantial reserve add to Tract 100, combined with pricing and performance-related revisions across our Appalachian acreage. Per unit LOE expense was up $0.08 per Mcfe over last year, largely due to higher transportation costs at Tract 100 and higher well workover and steaming costs in California. With respect to the transportation costs, the rates on the Trout Run system in Lycoming County are higher than on the Covington system, and thus, as Seneca produces more gas from Tract 100, we expect transportation costs to shift a little bit higher. Keep in mind that these costs are paid to our NFG midstream subsidiary, which saw a similar jump in earnings. NFG Midstream is becoming a more meaningful piece of the company. It generated substantially all of the $9.6 million of EBITDA we reported for the quarter in the all other category in our earnings release. Per unit G&A expense dropped by an impressive $0.13 per Mcfe on the strength of Seneca's increased production. Seneca's effective income tax rate for the quarter was unusually high at 49%, due to a $5 million, or $0.06 per share, adjustment to our deferred tax liabilities. Under the accounting rules, we're required to regularly reevaluate the effective rate used to calculate the deferred tax balances on our balance sheet. As our level of activity in Pennsylvania has grown, a greater percentage of our consolidated income has become subject to income tax in Pennsylvania, which at nearly 10%, has the higher corporate income tax rate of all the states in which we operate. While we're not paying current income taxes in Pennsylvania as a result of our tax clause, and we don't expect to for a while, we were required to make an upward adjustment to the rate we used to value our deferred tax balances, which increased our deferred tax expense. Looking forward, I expect our overall consolidated effective income tax rate for fiscal '13 and '14 will be in the range of 40% to 41%. The regulated companies had a good quarter as well. Earnings in the Pipeline and Storage segment were up $0.02 per share, largely on the strength of our recent expansion projects. Colder weather and a slight uptick in normalized usage per account in our Pennsylvania service territory caused utility earnings to grow by $0.03 per share. On the strength of our third quarter results and Seneca's increased production forecast, we're increasing and tightening our fiscal 2013 earnings guidance to a range of $3 to $3.10 per share. In terms of pricing, we are assuming NYMEX commodity prices of $3.50 for gas and $100 for oil for the remainder of the fiscal year. Our previous earnings guidance was $2.95 to $3.10 per share and assumed $4 gas and $85 oil. Our initial earnings guidance for fiscal '14 is a range of $3.05 to $3.30 per share. That guidance assumes Seneca's updated production forecast of 134 Bcfe to 146 Bcfe and flattened NYMEX pricing of $90 for oil and $4 for natural gas. In terms of realized natural gas prices, our forecast assumes the firm sales contracts that are summarized in the new IR deck that was posted on our website this morning. For production not subject to a firm sales contract, it assumes that the Dominion South Point Index trades at a $0.10 to $0.20 discount to NYMEX. While that basic assumption is in line with historic levels, it's a bit better than the current market. We expect that as a couple of large expansion projects on the Tennessee and Transco systems come online this fall, Dominion-based should return to recent historical levels. We've included a pricing sensitivity table in our earnings release that you can use to gauge the impact of different pricing assumptions. One last point on our firm sales agreements. Under those contracts, Seneca sells its production from Tioga and Lycoming Counties at the interconnection of NFG Midstream's gathering lines and the interstate pipeline network. Seneca doesn't typically hold firm capacity on the Transco or Tennessee systems, but is instead entered into sales agreements whereby it's effectively utilizing the firm capacity of various third parties. Therefore, when you're evaluating the sales prices summarized in the slide deck, remember that the prices represent Seneca's netback to the NFG midstream delivery point and, thus, reflect the cost of downstream transportation. While this ends up reducing our realized price for natural gas, our transportation expense, which is included within LOE, is likewise lower than it otherwise would have been. From an expense standpoint, we expect Seneca's 2014 per unit DD&A, LOE, production tax and G&A rates will all be in line with our third quarter rates. As a result of Seneca's increased production, NFG Midstream's earnings and cash flows should increase as well. For 2013, we expect NFG Midstream's revenue will be $55 million to $60 million, up from the $30 million to $35 million that we're currently forecasting for fiscal '13. Operating expenses will increase somewhat, as we add compression to the Trout Run system, but a large portion of the revenue increase will fall to the bottom line. You should note, too, that Midstream's forecast is based solely on Seneca's forecast volumes and doesn't assume third-party volumes. Turning to the regulated businesses, fiscal '14 will likely be a relatively flat year for the Pipeline and Storage segment. As you know, fiscal '13 capital spending in this segment was lighter than in prior years, with most occurring early in the year to wrap up some larger expansion projects. Thus, there aren't any major new projects that will come online within the next fiscal year. Fiscal 2014 will benefit from a full year of the Northern Access and Line N 2012 projects, but those increases will likely be offset by a small amount of recontracting and other capacity turnbacks that we expect in our legacy Supply and Empire systems. Lastly, with respect to the Utility, we're expecting a bit of a decline in that segment's earnings in fiscal 2014. Our forecast assumes normal weather in our utility service territory and a modest increase in operating costs. Our guidance also assumes we conclude the show cause order proceeding in our New York jurisdiction. We've commenced settlement discussions in that case and are continuing to dialogue with all of the parties involved in the proceeding. Turning to capital spending, our fiscal '13 budget of $710 million to $820 million is unchanged from our previous update. For fiscal '14, our consolidated budget is now a range of $790 million to $940 million. A breakdown of the consolidated total is as follows

[Matthew D. Cabell:]

Thanks, Dave, and good morning, everyone. As Dave mentioned, Seneca produced 34.1 Bcfe in the third quarter of fiscal '13, a 54% increase over last year's third quarter. In California, production continues to be slightly below our forecast. At CESP, the natural gas pipeline operator installed new compression, but it had only a minimal impact, and 200 to 300 Boe per day remains curtailed. Meanwhile, some of our older production has declined a bit faster than anticipated. The net result is that West Division production was 5.8% below last year's level for the third quarter. However, with plans for additional work on the CESP pipeline this fall, and new wells coming on at CESP, South Midway Sunset and Coalinga, we do expect to see growth in California in 2014. Moving on to our Mississippian Lime play in Kansas, we have successfully negotiated an increase in our working interest on what was originally our non-operated position. We now hold a 55% interest in this acreage and have taken over as operator. With this transaction, our total net acreage position is now 13,600 acres. We expect to spud our first horizontal well in November. In the Marcellus, our net production grew by over 50 million cubic feet per day from the second quarter to the third quarter as we brought on new Lycoming County wells. We will bring on one additional 5-well pad in late August. We expect production to be flat or up moderately in the next 2 quarters, with more significant increases in mid-2014 as we bring on 2 multi-well pads at Tract 100. Specifically, Pad N is a 7-well pad scheduled to come on this winter and Pad T is a 10-well pad scheduled for first production in the May, July timeframe. Note that a 10-well pad can produce 150 million cubic feet per day. So even a one-month swing in the timing of first production could change our annual forecast by as much as 4 to 5 Bcf. Moving on to our delineation drilling results on our legacy Western development area acreage. We tested 4 new wells in June and July. These wells are spread widely across our acreage and, therefore, provide new data over a large swath of our wholly-owned position. All 4 had good results, with the best well, the Clermont 9H, flowing as much as 8.9 million cubic feet per day and averaging 8.6 over this 7-day test period. The table is included in our latest slide deck, showing the lateral lengths and test rates from all 4 wells. Two important things to note. First, when normalized for lateral length, all 4 wells tested at higher initial 7-day rates than the original Rich Valley well, for which we now estimate an EUR of 7.4 Bcf. It's important to understand that the original Rich Valley well improved substantially after it was turned into sales, achieving higher rates than during the initial test period. Also, 3 days ago, we turned the Clermont 9H to sales. And over the past 24 hours, it produced 11.4 million cubic feet. This is a very strong well. Which brings me to the second important point, the Clermont Rich Valley area appears to be very strong, providing further confidence in our more immediate development plans. In fact, this area appears to be strong enough that we are now shifting some of our 2014 CapEx from Track 595 in Tioga County to this new development area at Clermont. We are no longer referring to this as a pilot program, but rather, a full-scale development project. We will have one rig dedicated to the area in 2014 and we'll be considering when to add additional rigs, depending on gas prices and longer-term performance of these new wells. Our Ensign 160 rig is just beginning to drill a 9-well pad. We have 150 to 200 well locations in the immediate area, and we expect the overall size of the area to grow as we delineate its geologic boundaries. Needless to say, we are pleased with these recent well results. I'm confident that we will be developing our Western acreage aggressively, with a progressively increasing rig count as gas prices improve and production and cash flow grow. Next week, we'll be testing 2 more wells at our Owl's Nest area, in an area where we expect wet gas with a BTU value of approximately 1,180. And we're currently frac-ing a well in our Tiny Nest [ph] area that should be substantially richer and should also yield condensate. We plan to test that well in November. Lastly, in the Utica, we have successfully frac-ed a 38-stage RCS well in the Mount Jewett area. Following a 30-day soaking period, we will be able to flow test that well in the first quarter of fiscal 2014. We remain excited about the Utica potential across large parts of our acreage. Let me conclude by saying that Seneca is embarking on the next step in its evolution. Our Marcellus development in Tioga and Lycoming County has enabled us to grow production from a company-wide rate of around 120 million cubic feet equivalent per day a few years ago to over 350 million cubic feet equivalent today. We have developed a world-class team that has proven their ability to identify and acquire high-quality acreage, and develop that acreage efficiently and effectively. Most recently, we've made huge strides in our understanding of our enormous Marcellus legacy position in Pennsylvania, and have greatly increased the potential output per dollar of capital spending, such that, I have more confidence than ever that we will be able to develop much of this area, economically, at a $3.50 to $4 realized gas price. Over the next 2 to 3 years, I expect this to become the primary focus of our development efforts and the primary contributor to our long-term growth. With that, I'll turn it back to Ron.

[Ronald J. Tanski:]

Thanks, Matt. Well, to sum it all up, we had a great quarter. Not just because of the solid numbers that we posted for the quarter and for the continuing trend in EBITDA growth that we started a number of years ago, but mostly for the recent success on our WDA acreage that sets up continued growth for our upstream exploration and production operations and our midstream pipeline operations for the foreseeable future. Specifically, in the Exploration and Production segment, we had at least 2 years of Marcellus drilling activity in Tioga and Lycoming counties, and we're excited about the running room we have on our WDA acreage that Matt detailed. And while the immediate opportunities in California aren't as large as our Appalachian prospects, our California operations and our new Kansas entry into the Mississippian Lime play, provide us with both commodity and basin diversity. It shouldn't be surprising that more than 2/3 of our overall capital spending during the past 4 years and projected spending in fiscal 2014 will be in the Exploration and Production segment. Just as Seneca is having success in the Marcellus, so are other producers, and they all need to get their gas supplies to market. Our midstream pipeline businesses have a number of projects designed to get both Seneca's and third-party production flowing. We've laid out those projects in our slide deck, so I won't spend a lot of time here on all the projects. There are 3 points, however, that are worth noting. The first is the addition of our Clermont gathering system to the project list. Based on our early well results on the Clermont acreage, we've committed to build a trunk line system with a design capacity of 500 million cubic feet per day. The second is a project that's not even on our listing. We call it our Tuscarora Lateral. It's a project targeted for 2015 to build 18 miles of pipe and a bidirectional interconnection between our Supply and Empire Pipeline systems that will allow our Empire system to offer storage capacity by utilizing Supply's storage fields. And while the project doesn't create a lot of new capacity, the increased flexibility gained on our Empire system will enhance service options and allow us to retain some customers under the long-term contracts and provide incremental revenues of over $6 million a year. In the long run, it may also provide a path for all the Marcellus gas connected to our Supply system to access markets served by Empire. Third, our Line N corridor remains very active. We're preparing our regulatory filings right now for the Mercer and West Side Expansion projects, and the team is already working on another project for 2016. Overall, our balance sheet is in great shape, and based on the capital expenditure program that Dave Bauer outlined for fiscal 2014, our base forecast shows that pretty much all of our financing needs can be met with our balance sheet. While there has been a lot in the financial news lately about corporate and financial structures, I'd like to address the subject before we open the line for questions. With respect to ONEOK's announcement of its utility spinoff, we've worked hard through the years to create a lean organization to run our regulated operations. And we believe that many synergies would be lost by divesting or separating our Utility from our Pipeline and Storage operations. Even though the Utility is becoming a smaller portion of the consolidated company due to the growth of the other segments, the predictable nature of the Utility operations and the stable nature of the cash flows provide significant support to our credit rating and help fund our ongoing dividends. So we're not considering a spin or divestment of the Utility. Looking at a master limited partnership, we believe that these are great vehicles to raise capital. For us, the critical piece of the equation is having a compelling use for that capital. Today, when we look at our funding needs, with our current plans to maintain a 3-rig Marcellus program, we're forecasting a modest outspend in 2014, which can be comfortably handled by our lines of credit. Looking forward, as many of you read in last week's release, and based on Matt's additional comments today, our WDA continues to demonstrate great success in its early delineation phase. And it's our expectation that it will ultimately grow beyond our current 3-rig program. However, the timing of the additional rigs will be dependent on 2 related factors

[Operator:]

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

[Carl L. Kirst:]

Maybe just a first question on the capital budget and specifically, the E&P capital budget, the $550 million to $650 million. We had always kind of thought maybe the decision of adding a fourth rig might be the big swing factor there. But if that's based on a kind of 3-rig program through the year, what's the -- what would be the primary swing factor in that CapEx budget?

[Ronald J. Tanski:]

I'm not sure that I fully understand your question, Carl. You mean, what would be -- what makes for the $100 million range?

[Carl L. Kirst:]

Yes, sir.

[Ronald J. Tanski:]

Well, a couple of things. One would be the activity level in Kansas, which would then be somewhat dependent on our success there. Another is our leasing activity in Lycoming County. It's not a huge number, but it could have an impact on that total. And I guess the third one is, is really more our pace of drilling and completions. If you frac a 6-well pad in 1 year versus another year, that can have a, say, a $25 million swing. So it's kind of a mix of all those factors.

[Carl L. Kirst:]

Okay. Now that's helpful. And -- so really the issue of kind of shifting from $595 million over to Clermont rather than adding a new rig at Clermont is just primarily an issue of gas price and bases at this point, kind of, I guess, same as it’s always been as far as the gaining factor?

[Ronald J. Tanski:]

Yes. For adding additional rigs beyond the 3? Yes.

[Carl L. Kirst:]

Right, okay. If I could ask one other question, just cost-wise and understanding that we're still sort of in this delineation and, perhaps, science experiment. But now that we've sort of gone officially in Clermont to a full development program, can you give us a sense of what you're expecting well costs to be? I don't know whether you can cite either -- the latest one, I think you said it was the 9H, or just general, what's your expectations are? But just want to make sure I've got that ring fenced.

[Ronald J. Tanski:]

Yes. Let me give it to you in terms of our expectations. As we go into this full development program, our expectation is that we'll be drilling wells that have, say, a 5,000 to 6,000-foot treatable lateral length. So they'll have, say, 33 to 40 stages. And the complete -- drilling complete cost for those would be $6.5 million to $7.5 million. So they're not cheap wells, but -- they're not cheap because they're long laterals with a lot of stages. And that's another reason why they are so effective. And we found that the bang for your buck is significantly better on longer laterals with more stages.

[Carl L. Kirst:]

Excellent. And then last question, Dave, and I apologize I was writing this down in your prepared comments. You said, turning to taxes, that the tax rate, you expect it to be 40% to 41% going forward. Did you make a mention of what you expected the sort of current deferred split to be in 2014, assuming no more bonus depreciation?

[Ronald J. Tanski:]

No, I didn't say that, but we don't expect to be paying any current taxes in '13 or '14.

[Operator:]

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

[Rebecca Followill:]

Just a couple of follow-ups. On the firm capacity or the firm sales that you have on the E&P side, can you quantify how much do you have under firm?

[David P. Bauer:]

Yes. Becca, we've got $125 million a day, firm, into TGP 300 and $155 million into Transco. And then we have another sort of $30 million to $70 million in the National Fuel system.

[Rebecca Followill:]

And then on the 9-well pad, I think, it was 92, we're looking to begin drilling on the Clermont area, what's the timing for that to go into service?

[Ronald J. Tanski:]

I think we'll have it drilled and completed, certainly, by the end of the summer. But I'm not sure if the gathering line will be complete by that date. So I would say, for forecasting purposes, I would assume around the first of our next fiscal year.

[Rebecca Followill:]

So that's what's built into your guidance?

[David P. Bauer:]

Yes.

[Rebecca Followill:]

Okay. So not really a '14 impact?

[David P. Bauer:]

Right. Clermont does not have -- other than the 2 wells that we've already drilled, doesn't have a material impact on fiscal '14.

[Rebecca Followill:]

And then to your comments on structure, and, I think, I was writing down also as you guys were talking, I believe you said that, it's over the next 3 quarters, you'll kind of evaluate what you want to do, how quickly you want to ramp up in that area and that really will kind of drive your decision on whether or not you need that capital to form an MLP, is that correct?

[Ronald J. Tanski:]

Well, Becca, it's really over the next few quarters, we're going to be looking at gas pricing and basis, to see if there is a way that we can provide a little bit more clarity with respect to future cash flows that might be -- well, that would form the basis of ultimate dropdowns in an MLP format, or really just the economics of drilling the wells in the WDA.

[Rebecca Followill:]

So what specifically are you looking for? What would be the threshold that would drive that decision?

[Ronald J. Tanski:]

Well, again, the pricing. I mean, Matt talked about a netback of $3.50 to $4 to Seneca for the production in that area. And as you know, basis is, as Dave mentioned, is struggling a little bit at Dominion South Point these days, and it's really tough to get any kind of long-term contracts out of that area right now.

[Rebecca Followill:]

And then finally, just in light of that, of the bottlenecks that we're seeing, and they're really compressed, or the wide basis that we're seeing, any progress on your West-to-East project?

[Ronald J. Tanski:]

No, not -- no major progress. That's still sitting out there because with the -- what we're seeing for the dry gas portion, other producers out there haven't been actively drilling a lot of wells, looking for capacity. Everyone, as you know, is concentrating on the wet gas window.

[Operator:]

[Operator Instructions] Our next question comes from the line of Tim Winter with Gabelli.

[Timothy M. Winter:]

I was wondering if you could talk a bit more about the show cause order process? That slide on Page, I think, 37, shows the most recent plan was the 9.4% allowed ROE. Where are you guys trailing 12 months? And what is sort of built into your guidance for 2014?

[David P. Bauer:]

Well, for the trailing 12 months, we're a good amount higher than that. I don't have the exact number at my fingertips. In terms of guidance, we've assumed a -- that we, ultimately, reach a settlement, that we're -- as I said earlier, we're in settlement discussions currently. And that's a confidential process, so there's -- I'm kind of limited in what I can say, but we have taken the -- an assumed settlement into account in our guidance.

[Timothy M. Winter:]

Okay. And if, for some reason, there wasn't a settlement, what would sort of the timeframe be of an official rate case decision?

[Ronald J. Tanski:]

Well, as I understand it, there isn't a set end date to the show cause proceeding, unlike a typical rate case, where there's a procedural schedule. This, as I understand it, can -- doesn't have a set end date.

[David P. Bauer:]

But to put some outside parameters around that, I mean, if we envision that settlement discussions weren't heading anywhere, in particular, or productive, we'd be looking at filing a case, and that would put an 11-month statutory timeframe on coming up with a final rate decision.

[Timothy M. Winter:]

Okay. But then rates would still be temporary as of June 14th?

[Ronald J. Tanski:]

That's right.

[Operator:]

Your next question comes from the line of Holly Stewart.

[Holly Stewart:]

Just 2 quick ones. First, for Matt. In Tioga, Matt, given the decline in gas prices, are you still planning on bringing that multi-well pad on?

[Matthew D. Cabell:]

Yes, we are, Holly. We have $125 million of firm sales there. The other wells, obviously, are declining, as you'd expect them to be. And the timing works out good for us to bring that on. The other thing is, it's first production will come on just about the same time that some of the new projects are completed in the Northeast. So we're hopeful that the significant basis differential will allow for spot sales as well.

[Holly Stewart:]

What specifically is that timing?

[Matthew D. Cabell:]

There are several projects that come on in November.

[Holly Stewart:]

Okay. So this is supposed to hit the fiscal '14?

[Matthew D. Cabell:]

I'm sorry. Are you asking what time does Pad C come on? Or are you asking when the other projects are that are related to the issues?

[Holly Stewart:]

Well, the Tioga pad, specifically.

[Matthew D. Cabell:]

Yes, the Tioga pad, we'll begin frac-ing it very soon, probably have it online by November, December kind of time frame.

[Holly Stewart:]

Okay. So that's in your guidance?

[Matthew D. Cabell:]

Yes, it is.

[Holly Stewart:]

Okay. And then you mentioned beginning to test some of the wetter areas. How are you guys planning on handling liquids?

[Ronald J. Tanski:]

Well, the less wet areas, we can handle with ethane rejection. So even something like Owl's Nest, we can probably handle with ethane rejection. When you get further west to something like our Tiny Nest [ph] area, it's going to require some kind of ethane solution, and those should be some significant value add for the heavies there. So at this point, our goal is to get a test on this well, see what it'll do. A long-term development solution would require a lot more planning.

[Operator:]

There are no other questions at this time.

[Timothy Silverstein:]

Thank you, Gwen. 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

[Operator:]

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a wonderful day.