National Fuel Gas Co (NFG) 2007 Q2 法說會逐字稿

Good day, ladies and gentlemen. Thank you for standing by, and welcome to the second-quarter 2007 National Fuel Gas Company earnings conference call. At this time, all participants are in a listen-only mode. We will facilitate a question-and-answer session toward the today's conference. (OPERATOR INSTRUCTIONS) I would now like to turn the presentation over to your host for today's call, Ms. Margaret Suto, Director of Investor Relations. Please proceed, ma'am.

Good morning, everyone. Thank you for joining us on today's conference call for a discussion of last evening's earnings release. With us on the call is Phil Ackerman, Chairman and Chief Executive Officer of National Fuel Gas Company; Dave Smith, President and Chief Operating Officer of National Fuel Gas Company; Ron Tanski, Treasurer and Principal Financial Officer of National Fuel Gas Company; and Matt Cabell, President of Seneca Resources Corporation.

At the end of the prepared remarks, we will open the discussion for questions. Also, since this call is being publicly broadcast, we remind you that today's teleconference discussion will contain forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. 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. You may refer to last evening's earnings release for a listing of certain specific risk factors. With that, we will begin with Phil Ackerman.

Thank you, Margaret, and good morning. In many ways, the quarter was the kind of quietly productive period which has been the backbone of growth of this Company. Earnings were up in utility, marketing, and timber due to Pennsylvania rate relief and better weather, which affects both our gas-related businesses and timber harvesting.

In Exploration & Production, we had a couple of nice discoveries and a modest increase in production, although earnings were down because of some tax items.

Pipeline & Storage was down, as should have been expected, due to the rate settlement effective December 1, 2006. As is typical of the cycle in that business, the challenge now is to add customers and volumes to bring profits back to where they were.

Finally, and perhaps most significant, we were pleased to raise and narrow our earnings guidance to $2.25 to $2.40. With that, I will turn it over to Ron Tanski.

Thanks, Phil, and good morning, everyone. For the second quarter of our fiscal year, our earnings were pretty much in line with our expectations. Last evening's earnings release provides the explanation of the period-to-period variances, so I won't repeat them here.

In terms of any trend changes in segment earnings that you can see in the date there are two that I will point out. But they should not be surprises.

The first is the decline in the earnings in the Pipeline & Storage segment as a result of lower efficiency gas sales volumes. Over the past few years, the Pipeline & Storage segment had made annual sales of approximately 3 Bcf of efficiency gas. Our Settlement Agreement recently approved by FERC has reduced those volumes by about one-half. We have already talked about this in previous calls; so you should have already updated your forecast models to reflect that change.

The second trend change is the increase in the utilities earnings in the Pennsylvania segment, as a result of new rates that went into effect in January. While weather was also colder than last winter, the new base rates are designed to increase revenues by approximately $14 million on an annual basis.

Looking to the future, we will continue to be busy with our rate proceedings in New York. As I mentioned at the American Gas Association conference that was webcast last week, the New York Public Service Commission issued an order on April 20 in two companion dockets requiring utilities to file true-up revenue decoupling mechanisms, or RDMs.

The Commission's order requires utilities to develop and implement mechanisms that true-up forecast and actual delivery service revenues. The RDMs will be designed on a case-by-case basis; and each utility's upcoming base rate proceeding -- in our case that we filed on January 29 -- already includes an RDM proposal.

Now according to the procedural schedule in that case, the testimony of staff and other parties is due to be filed on June 7. At that point, we will see what staff and the other parties think of our proposal. But based on the ordering language and the generic cases, however, I think it is safe to say we will have an RDM in our New York jurisdiction by January.

Regarding the Company's buyback of its common shares, during the last quarter the Company repurchased 11,400 shares, bringing the total repurchases through the end of March to 3,721,878, for a total of $128,512,000. That is an average price per share of $34.53.

Phil mentioned the increase in our earnings guidance. As we pointed out in last night's release, that increase is primarily due to the hedging of efficiency gas volumes that the Pipeline & Storage segment plans to sell in the fourth quarter. Our original forecast included selling those volumes at an average LIFO accounting price of approximately $5.92 per decatherm. Now we have some hedges layered in to sell that gas at an average price of $7.88 per decatherm. Since we locked in those higher prices, we were able to increase the guidance range.

Now I will turn the call over to Dave Smith.

Thank you, Ron, and good morning to everyone. Though the second quarter was fairly uneventful, each of our segments posted strong financial results. As Ron said, consolidated earnings were in line with our expectations.

More importantly, at least from a long-term perspective, we continue to make progress in addressing areas of concern and in developing new opportunities. The Company is well positioned for the future.

In the New York division of our utility, which accounts for approximately two-thirds of our utility business, two of our long-standing concerns -- uncollectibles and usage per account -- have been and are being addressed in a fashion that is mutually beneficial to National Fuel and to our customers.

Our merchant function charge protects against spikes in uncollectible accounts as a result of rising gas prices. The continuing decline in usage per account should be resolved by the implementation of a revenue decoupling mechanism by early January 2008.

We are hopeful that Pennsylvania, which is also considering revenue decoupling, will join the growing number of states that have approved RDMs -- coupled, of course, with a conservation incentive program as a means encouraging conservation and reducing energy bills ultimately paid by our customers.

Turning to the Pipeline & Storage segment, I'm happy to report that on February 9, the Federal Energy Regulatory Commission issued an order approving the settlement we reached in the Section 5 proceeding. We implemented the settlement effective December 1, 2006. As Ron said, the drop in efficiency gas volumes brought about by that settlement, which we did anticipate, was the principal driver behind the decrease in the Pipeline & Storage segment earnings from the prior year.

Importantly, the settlement provides for the full recovery of the existing OPEB regulatory asset; adjusts our ongoing OPEB expense to a more current level; and provides the security of continued OPEB deferral accounting treatment into the future.

With the final resolution of the Supply Corporation rate proceeding, we are focusing our attention on expanding the Pipeline & Storage segment of our business. In the near term, much of that growth will come through the Empire Connector Project.

As you know, rising pipeline construction costs have been a concern. Previously, we projected the cost of the project to be at a $152 million. But because of a rise in contractor costs, we recently revised our estimate to $177 million. We have done our best to control our costs and generally have been very successful. As of today, most of the cost of materials for the project -- including the cost of both the pipe and the turbo compressor units -- have been locked in at amounts that are consistent with our $177 million estimate.

We have competitively bid the pipeline construction work; and indeed, bids are due this afternoon. Now obviously, it makes sense to build the project only if we believe it will generate an acceptable rate of return. And a 16% increase in capital cost clearly has a significant impact on the project's economics.

After significant effort and cooperation between all the parties, the Industrial Development Agencies in the six counties through which the line will extend all passed resolutions in favor of property tax abatements and sales tax exemptions. Assuming the pipeline construction bids meet our expectations, and we expect they will, the tax savings generated by the IDAs will offset the impact of higher capital costs.

Now aside from construction bids, all that remains are two environmental permits, both of which are expected within the next couple of weeks; and of course, the acquisition of necessary land rights, which we have already commenced.

All in all, we are very happy with where we stand on the project. We have got a little work to do, but we have every confidence we will execute our firm service agreement with KeySpan by the end of the month. After that, the first phase of construction will start in September of 2007 for a target in-service date of November 1, 2008, to coincide with Millennium.

Looking beyond the Empire Connector Project, we see excellent opportunity for further growth in the Pipeline & Storage segment. From the proposed Rockies Express Project, to the Cove Point LNG Project, and the increasing interest in Appalachian drilling and in production, clearly there will be a long-term need for new transmission and storage capacity in our region.

And National Fuel intends to be a major provider of such services. Further, we will continue to explore the development of non-regulated gathering and processing systems to support the growth in Appalachian production.

Now in the E&P segment, we believe that Seneca under Matt's guidance is back on the right track. An appropriate disposition of the Canadian properties; a refocusing of our efforts in the Gulf; and the expansion and acceleration of our drilling program in Appalachia -- all of which Matt will discuss -- will, in our judgment, improve Seneca's performance immediately and over the long term.

So should the infusion of new talent. To that end, Matt recently recruited John McGinnis from Dominion to cat up our exploration program. John has experience in all of our production areas with the exception of Canada. With Matt as President, John as Senior Vice President of Exploration, Barry McMahan -- whom many of you know and who has always run a low-cost operation -- as Senior Vice President of Operations, we believe we have a strong and solid team that bodes well for Seneca's and, therefore, National Fuel's future.

With that, I will turn it over to Matt for an update on Seneca.

Thanks, Dave, and good morning, everyone. This has been an exciting quarter for Seneca, with two important discoveries, one in Appalachia and one in the Gulf of Mexico. Before discussing these discoveries and Seneca's results for the quarter, I would like to take a few minutes to explain how our E&P strategy is changing.

As you are aware, our finding and development costs over the past several years have not been competitive. To address this, we will take a more focused approach, restricting our activity to three geographic regions instead of four. Within each region, particularly in the Gulf of Mexico, our efforts will also be more focused, with an emphasis on areas where we have had success or where we have some other competitive advantage.

As we have announced, we plan to exit Canada. The Canadian program has shown some recent promise; but overall it has not met our original expectations, and it lacks synergy with our other regions. The Canadian sale process is underway, with data rooms opening later this month; bids due in late June; and an expected transaction closing date prior to the end of our fiscal year.

We expect the sales price for our Canadian assets to be considerably more than the current book value of just under $100 million. As you may recall, Seneca was required to take an impairment at the end of last fiscal year when year-end gas prices in Canada dipped to approximately C$370 per MMBtu. Hence the relatively low book value.

In the future, we will focus our efforts on our growing Appalachian development; our very profitable California oil operation; and, as I said, on specific areas of interest in the Gulf of Mexico. Fiscal 2007 capital spending will be reallocated accordingly.

Our original budget of $212 million will be cut to $196 million. We had about $100 million dedicated to the Gulf of Mexico, while our revised 2007 budget will have approximately $64 million for the Gulf. Meanwhile, Appalachia will have an increased share of the CapEx, from an original $35 million to a revised $48 million.

Although our fiscal 2008 budget is not yet set, I would anticipate a further shift such that the Gulf of Mexico is no more than a third of the total and Appalachia is at least a third.

Moving on to our second-quarter results, in the East or Appalachian region, we're still a bit behind on our drilling target due to weather-related constraints. However, we expect to run four rigs throughout the summer and should still be able to drill a total of 200 wells for the fiscal year. Next year, we plan to drill 250 Upper Devonian wells, and we hope to reach 350 per year by 2010.

This is a prudent growth rate that will allow us to successfully develop our acreage, while adding maximum value. It is important to understand that individual well recoveries and production rates are lower in this Northern part of the Appalachian Basin than they are further South due to our position within the Basin and the consequent stratigraphic complexity.

As we continue with our geological work and as we drill new wells, we are constantly updating the regional picture. Therefore, even if we resolve all of the operational constraints, there is still a natural limit to our drilling pace.

Over the past five years, our average well has added about 90 million cubic feet equivalent of reserves with first-year production of 10 to 12 million cubic feet, if you include the condensate yield. This is lower than what some other operators are reporting to the South and the more Central part of the Basin. Therefore, it is critical that we do not simply drill these wells on a grid; but rather we incorporate all of the data from the wells as they are drilled and locate our wells such that we drill where we can get the best rates and recoveries.

With good, regional geologic work that incorporates the data from every new well drilled, we believe we can maximize the average per-well reserves and production, and maximize the value of these assets.

Additionally in the East, we have participated in a successful wildcat well in Forest County for a deeper formation. That well was tested at rates as high as 6 million cubic feet per day and will come on line at 1 to 1.5 million cubic feet per day, or roughly the equivalent of 40 of our typical Upper Devonian wells. Seneca has a 50% working interest.

This discovery may open up a new exploration for us, as we have an excellent acreage position on trend. However, this is not a resource play. If successful, these will be individual, isolated accumulations.

Regarding the Devonian shale joint venture with EOG, the first well has been drilled to TD and logged. We will make a detailed evaluation of the core and other well data, but plan to keep all data confidential.

Moving to the West, we have drilled 33 development wells at Midway-Sunset so far this fiscal year. We have also expanded the steam generation capacity and enhanced the waste gas scrubber. These new wells and production enhancements have brought production back to near year-ago levels in the West, as well as helping to reduce costs.

In the Gulf, we have drilled a significant discovery offsetting last year's Highland 24-L well, in which we have a 35% working interest. This second well, which was drilled on the newly acquired northern lease, encountered approximately 100 feet of pay and tested at a rate of 50 million cubic feet per day. This additional success will provide a very nice production boost when it comes online in August or September.

Overall, production for the quarter was 12.2 Bcfe, bringing us to 24.2 Bcfe year to date. We are on track to meet our production guidance of 47 to 52 Bcfe, but near the lower end. More importantly, we are excited about our recent drilling results and looking forward to further success with our more focused program.

Operator, we can turn it over to questions now.

(OPERATOR INSTRUCTIONS)

Operator, are we not registering any questions?

(OPERATOR INSTRUCTIONS) Becca Followill of Pickering Energy Partners.

Good morning. A question for you, Matt. The Forest County well that you drilled, what formation were you targeting?

That is the Onondaga limestone.

Okay, thank you. Who is your partner in that?

Our partner is a company called PGE, and they operate that well.

After that discovery, how many more wells do you have planned in that area? Any further insight on what kind of opportunities you see?

We don't have any additional wells planned. Really, the point is it is a formation we haven't been targeting. Again, we have a good acreage position on trend, and we believe there is additional potential. Probably the next step will be to acquire some seismic data.

Perfect. Thank you.

Carl Kirst of Credit Suisse.

I apologize if this was said in comments; I jumped on the call a little bit late. Matt, I believe the 3P report that is being done in the Appalachian, you said that was Netherland Sewall from a prior conversation. I guess I'm just wondering if you could refresh my memory. The timing of completion of that, first off?

Sure, Carl. We expect to have that report sometime this summer, certainly well before the end of the fiscal year.

Okay, thank you. Just to clarify the discovery that was made in the Gulf of Mexico, you said that tested at 50 million a day. The ownership, Seneca's ownership of that, I'm sorry, was 35%?

35% working interest.

Okay, and that is coming in on August or September?

Right, it is looking like it is probably closer to September 1 than to August 1. The success, actually, to some degree has delayed the first production, because we need bigger facilities.

Fair enough. I know you guys have probably been asked this many times in the last couple of weeks. But just with some of the prices that have been paid in the Gulf of Mexico, and of course understanding what just happened with Dominion because of their deepwater -- so a little apples and oranges here. But have any of the recent transactions gotten you to think differently about monetizing the Gulf?

No, Carl, I don't think so. Our view is that we still have some opportunities, very focused opportunities within the Gulf; and that those opportunities, the present value of those opportunities is greater than what we would get from a sale.

Also I think it is important to recognize that the Dominion assets are very different from thee. I would use a comparison, if you were going to use a comparison, I would pick something more like Cabot's sale to Phoenix, which is still a good sale, but not quite the same price per Mcfe as Dominion received.

Sure. Okay, thank you for your time.

(OPERATOR INSTRUCTIONS) David Thickens with Deephaven Capital.

Good morning. A couple questions, just housekeeping on the 3P reserve report that is going to come -- that you're going to release this summer. Am I correct --?

Let's just stop right there. We didn't say that we were going to release it this summer. We said we were going to receive it this summer.

Oh. Are you planning on -- so --

We will cross that bridge when we come to it.

Okay. What would the reasoning be for not sharing it with your investors, potentially?

Well, we will just have to see what kind of confidence we have in those numbers when we get them.

Okay.

We have said that right along, that we had commissioned the study and we may or may not release it, depending.

Okay, I missed that distinction. Am I correct in that it is -- you're targeting just the sandstones and not the shales?

That's right.

Okay. The other question, I'd just maybe ask you to talk a little bit more about your pace or potential acceleration of the drilling program you have outlined in the shale wells. Other players -- admittedly to the South of you -- are really talking about marked accelerations in their plans. But at AGA you outlined a much more deliberate drilling program, but had specific number of wells, well out past 2010.

Kind of curious why you are putting numbers out there. Is that just that you believe that the shales, where you are, are not as prolific as they will be farther South? You are still unlocking things from a technical perspective, and depending on what you find you may accelerate? What? Can you just give some more color on that?

Sure. What you have to keep in mind is what we presented at AGA is the required drilling pace under the joint venture with EOG. They need to drill at that pace in order to keep this program, this joint venture, alive.

Now given that, they're still -- drilling in this part of the Basin for the shale is still going to be relatively new; and it has a natural pace as well. So I don't expect it to be greatly accelerated within the first year or two.

However, with great success, it might be accelerated tremendously. Also, with lack of success, we might just cut it short.

Okay.

No indication that we have any reason to believe it is any better or worse than the Southern part of the Basin at this point. We don't have any well results, yet.

Okay, thank you much.

There are no further questions at this time. I would like to turn the call over to Ms. Margaret Suto for closing comments.

Thank you very much. I guess we will conclude our call for the day. We want to thank everyone for taking the time to be with us. A replay of this call will be available in about one hour on both our website and by telephone. Both will run through the close of business on Tuesday, May 15. Or Web address is www.nationalfuelgas.com. The telephone replay number is 1-888-286-8010 using pass code 99121557.

This concludes our call for today. Thank you and goodbye.

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