National Fuel Gas Co (NFG) 2006 Q2 法說會逐字稿

Welcome to the second quarter 2006 National Fuel Company conference call. As a reminder, this conference is being recorded for replay purposes. I would now like to turn the call over to the presenter Margaret Suto, Director of Investor Relations. Please proceed, ma'am.

Thank you, Amanda. Good morning, everyone. Thank you for joining us today on this conference call for a discussion of last evening's earnings release. On the call today we have 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, Principle Financial Officer of National Fuel Gas Company; and Jim Beck, President of Seneca Resources Corporation. At the end of the prepared remarks, we will open the discussion to 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 and you may refer to National Fuel's most resent form 10-Q for a listing of specific risk factors. With that we will begin with Ron Tanski.

Thank you, Margaret. And good morning, everyone.

As last evening's earnings release indicated, our second quarter net income of $78.6 million was in line with our expectations. It was primary the impact of commodity pricing during the quarter that reduced earnings below our guidance range. With the wide swings that we continue to see in the commodities market, we believe the most useful information we can give you for your earnings models, is to let you know the prices that we have built into our earnings forecast and give you a sensitivity table that'll let you calculate your own earnings estimates for future periods as those prices change.

I'll continue the practice of not using time during this call to repeat what we've already set out in earnings release. At the segment level, though, I will add a little more color to the detailed numbers we have in the back pages of the release that might point to certain trends. The utility segment throughput was down by approximately 7 Bcf for the quarter and for the first six months of the fiscal year.

Obviously, a lot of that was due to the warmer-than-normal winter that we had, but on a normalized basis, we're still seeing a conservation trend by our residential customers. A recent calculations using the 12 months ended March 2006 show that our New York residential customers now burn an average of 106.3 Mcf per year. A year ago, that average usage per residential account was 110 Mcf per year.

In Pennsylvania, the trend has been the same. The average usage per residential customer for the 12 months ended March 2006 was 100 Mcf per year. And a year ago, the average usage was 106.3 Mcf per year.

Operation and maintenance expense in the utilities segment for the quarter was 3% higher this quarter as compared to last year, and was primarily due to a higher accrual of bad-debt expense. At the beginning of the year, when we increased our overall accrual rate for doubtful accounts, we more closely tied the timing of the accrual to the utility throughput and revenues. Since most of the utility throughput and revenue, including unbilled revenue, occurs during the winter period, that's when we accrue most of the bad-debt expense.

Before this year, the timing of the bad-debt accrual did not factor in on build revenues. Now last year, we accrued an expense for doubtful accounts at a rate of approximately $19.5 million for the entire year. And we had accrued 67% of the total through March. This year, we plan to accrue a $25.1 million expense for doubtful accounts, and we've already accrued 78% of that total.

In the pipeline and storage segment, the $2 million increase in operation and maintenance expenses year-over-year was primarily due to the timing of the recording of higher pension expense this year and the fact that some operation and maintenance credits that we had in last year's second quarter did not recur this year. This large jump is not a trend that we expect to continue, and you should look at the six month numbers as an overall guide. The year-over-year decrease in other income relates to supply corporation's sale of base gas last year that did not recur this year.

I think we explained all the other year-over-year changes in the release, except the adjustment to deferred tax expense in the exploration and production segment. There are a lot of estimates in our tax provision that get adjusted regularly as a result of reconciliation, audits, and changes in estimates.

Back in the fiscal 2000 to 2003 time frame, we made various estimates about our ability to fully deduct the cost basis of certain of our Canadian properties on our Canadian tax returns. To the extent we thought we'd be able to use those deductions, we established a deferred tax benefit on our balance sheet. Because commodity prices were much lower then, our forecasts of future taxable income did not suggest that we'd be able to fully utilize those deductions, so we didn't record them on our books. Now, with a high commodity pricing apparently here to stay, we took another look at those estimates and concluded that, in fact, we would be able to utilize the deductions. So we reestablished the deferred tax benefit on our books.

Now you can debate whether to classify this adjustment as recurring or non-recurring, but since it was simply a change in one of our estimates, albeit a large one, it was no different from the many estimates we regularly make, and we elected to not highlight it as non-recurring.

Now I'll touch on the revised earnings guidance range. The major change is the decrease in projected earnings in the exploration and production segment due to price decreases from the NYMEX pricing strip that we used to develop our original forecast. Our revised forecast has included increased throughput and pricing in the pipeline and storage segment as well as increased sales by the energy marketing segment. Otherwise, there have been no other fundamental changes in our operations that have caused a revised forecast to be substantially different from our original expectations.

I will repeat one item that's in the release. Our current revised guidance does not take into account the increase to our earnings per share numbers that is expected to result from our share buyback program. By factoring in a lower number of shares outstanding after the buyback, we've projected that the earnings range for the fiscal year might be $0.03 per share higher and actually reach the original forecast level, however, we wanted to keep the forecast base comparable so analysts could analyze the operating earnings on a consistent basis.

Now I'll turn the call over to Jim Beck for a discussion of the details of the exploration and production segment.

Well, thank you, Ron. And good morning, everyone.

It's becoming more apparent that the increase in demand for oil in China and India has helped maintain high oil prices in the United States. As a result, Seneca had another very good quarter. Financially, the high commodity prices helped Seneca achieve a 129% increase in earnings. Operationally, our 100% drilling success has helped maintain production for the future. A review of the financial results are summarized in detail on pages 19 and 20 of yesterday's earnings release.

Briefly, production for the quarter was 12.1 Bcfe. The revenues for the quarter increased 26.1% to $88.7 million, and Seneca's net income for the quarter increased to $25.8 million or $0.30 per share. In the Gulf, Seneca is currently participating in one exploratory well on [Vermilion] block 342. The Gulf production increased 65% over the first quarter. We continued with repair to the damage of pipelines and platforms caused by Hurricane Rita, but we do not expect to have all the repairs completed for at least three more months. In addition, East Cameron 213, the B-1 well is now on production at a rate of 3.8 million cubic feet per day.

The refurbishment of the Todco rig 256 is proceeding on schedule. It now appears that it will be available to start drilling for Seneca in July. And Seneca continues to develop more prospects to utilize this rate, excuse me. In March, the offshore lease sale, Seneca was apparent high bidder on four blocks, two of these blocks have been awarded to us so far.

In Canada, the Canadian activity has been limited due to the tight rig market in the early spring thaw. During the second quarter, we drilled seven wells and had a 100% success rate. We expect the third and fourth quarters will have an increase in drilling activity, as we have received approval from the Alberta government for a drilling program to down space our Stan Moore oil field. This will add a six-well program, in addition to the other wells to be drilled in the Drum Heller area. We're still waiting for Talisman to provide an update on our activity in Sukunka. We hope to make an announcement in the near future.

In California, the new scrubber began operations in mid-January and is now at full capacity burning waste gas to generate steam. Seneca will realize the full benefits of this equipment in the third quarter by reducing steaming costs by an estimated $250,000 per month at current gas prices. However, we have already incorporated these savings in our current forecast. A total of 27 wells were drilled in the second quarter. In addition to this, shallow drilling will continue -- we will continue to do the shallow drilling.

Seneca plans on drilling five wells in South Lost Hills Field starting in May. Three of these wells are in the acreage mentioned in the earnings release yesterday where we completed the strategic acquisition of 640 acres and three wells on contiguous acreage -- or on acreage contiguous to our South Lost Hills acreage.

Looking ahead, for our expectations for the third quarter, we expect production to be between 11 and 13 Bcfe. We expect to drill approximately 60 wells, mainly in our west and east divisions. edging for the next six months of fiscal 2006 can be summarized as follows: for your information, the forward price as of April 24, 2006, was used for the colors to calculate the weighted average prices of the gas hedges. For the remaining six months, we have 7.5 Bcfe of gas production hedged at an average price of $7.10 per Mcfe and 900,000 barrels of oil hedged at an average price of $35.33.

he impact of price changes on earnings for the remaining six months as as follows: for each $1.00 change in oil price for the next six months, earnings will change $0.01 per share and for each $1.00 change in gas price for the next six months, earnings will change about $0.06 per share. For the remaining six months of fiscal 2006, we're focused on expanding our activity through drilling and looking for another strategic acquisition.

At this point, I'll turn it over to Dave.

Thanks, Jim. And good morning to all.

As you know, we had a strong first quarter in 2006. Our second quarter continued to build on those results. Despite significantly warmer-than-normal weather, despite a continuing decline in usage per account in our utility, and despite the recent softening of gas commodity prices in last quarter, we remain on track to achieve record earnings for the year. Our release and Ron's update provide you with extensive financial information broken down by segment. There's no need for me to go over that material again, as we prefer to leave time for your questions.

I will take a few minutes to supplement the release with additional information on a few of our segments. Given the challenges it faced this heating season, the utility, and particularly the New York division of the distribution corporation, contributed a solid and stable performance. Earnings were up in New York, but down in Pennsylvania. Largely because of warmer-than-normal weather. Unlike New York, Pennsylvania does not have a weather normalization clause, and lower usage per account. Because earnings were down, on April 28, the 2006, we served notice with the Pennsylvania PUC indicating our intent to file for a general base rate increase.

This prefiling notice, which is required, is standard operating procedure and is designed to provide staff and interveners with notice that there is a, "substantial likelihood of a base rate filing in the near future." We are preparing that case presently and anticipate filing on or about May 31st, 2006.

Moving to the pipeline and storage segment, that segment continued its strong performance in the second quarter. There are two current and ongoing matters on which I will comment. The first is the Empire Connector, which as you know is our proposed 78-mile, 24-inch pipeline from our existing Empire line in Victor, New York, to the proposed Millennium pipeline in Corning, New York. That project continues to proceed according to plan.

We have encountered no major setbacks and are pleased with the progress today. As of March 31st, 2006, Empire has incurred $5.1 million in costs related to the project, all of which have been reserved. We anticipate that FERC will issue a decision on our application and on the Millennium application by this November. The targeted in-service date is November 1st, 2007, and Empire, Millennium, and the other participating pipes are diligently pursuing the regulatory, environmental, engineering, and commercial issues that need to be resolved. We are hopeful and optimistic regarding an '07 in-service date. In any event, be it 2007 or 2008, we anticipate being ready to serve when Millennium is ready.

On another front, we announced in early April that a complaint has been filed at FERC against the Supply C corporation by the New York Public Service Commission, the Pennsylvania Public Utility Commission, and the Pennsylvania Office of Consumer Advocate. That complaint asked FERC to find that supply corporations present rates are unjust and unreasonable and to establish rates going forward that will be just and reasonable. The complaint also questions whether supplies past and ongoing sales of efficiency gas were authorized. This has an ongoing litigation, so as you might expect, there is a limited amount we want to say publicly.

Supply answered the complaint last week regarding efficiency gas sales. Our answer includes extensive documentation of Supply's authority to make its previous and ongoing sales. In short, we believe this allegation to be without merit and thus have not accrued any expense. Regarding rates and fuel retention moving forward, we contend that our overall rates are just and reasonable and within the range of what FERC could considered to be just and reasonable in a proceeding of this nature.

We also pointed out in our answer that a return on equity of 10.17 as suggested by our opponents would not be sufficient to attract investment of discretionary capital to pipeline and storage projects. As you know, the general subject of what is an appropriate return on equity is currently the subject of considerable attention in the industry and at FERC. The complaining state agencies also moved for summary disposition, asking FERC to immediately reduce Supply's fuel retention rate before resolving the issue of whether Supply's overall rate are unreasonable.

We responded that it would contrary to FERC precedent and fundamentally unfair to immediately lower our retention rates without considering overall costs and revenues in a fully litigated proceeding. The money we have made by selling excess retained gas is what have enabled us to live with our monetary rates without filing a general rate increase since 1995. We believe we will prevail on this motion for summary judgment and that we will litigate or settle the matter of our future overall costs and revenues.

I'm not going to speculate how long it will take to resolve this proceeding. It could take some time. Or whether and by how much our existing rates might change. I will say we will vigorously defend our existing rates and that we haven't changed our earnings guidance for 2006. Any earnings guidance we provide for future periods, we'll let you know what assumptions regard supply rates are embedded in that guidance.

Finally, one brief comment on the timber segment. While cherry sales were down 22% quarter-to-quarter, which was due to weather in the second quarter, 2006's six month's performance including cherry 's sales is actually up. On that note I'll turn the floor over to our Chairman and CEO, Phil Ackerman.

Thank you, Dave. And good morning, everybody.

This winter showed we are still a weather sensitive company. But in spite of extraordinarily warm weather in our area and across most of the U.S., we are still on track for record earnings. This is a reflection of our decreasing dependence on our local utility operations and reinforces my belief in the wisdom of our diversification and pipelines and production. Many of you were at our analyst's seminar in March, and the feedback was generally very positive. So I probably should leave well enough alone, but there does seem to be some confusion about a couple of things.

First, our exploration and production operations in the Gulf of Mexico. We aggressively moved into the Gulf of Mexico in 1991 when 3D Seismic was a relatively new technology and most of the Gulf had not yet been covered by it. The majors were not especially interested in the shallow waters of the Gulf and for awhile, competition was relatively weak. However, competition soon intensified. The Gulf was covered with 3D. Gas prices were bouncing around below $2.50. Costs were increasing. And I concluded that our days in the Gulf were numbered. I was not unhappy with the Gulf, physically. It was economically. I believed that there would come a time when we would not be able to find economically attractive drilling prospects there, at the same rate as we had been finding them. I still believe that. But this new level of gas and oil prices has changed the economics and our experience and expertise remain applicable. Unless gas and oil prices continue to rise or technology has another breakthrough, we will, eventually, leave the Gulf.

But in the meantime, we are actively looking for new opportunities there. And as Jim said, we were recently the apparent high bidder on four blocks.

The second area is my outlook for exploration and production. I think people get mixed signals about my enthusiasm for E&P, depending on the time horizon. At these prices, I am extremely glad we made the decision to stick with and expand E&P. Our existing reserves will be wonderful money makers and I expect the returns on the capital we are current investing there will be most gratifying.

However, there are some fundamental reasons why my enthusiasm for E&P is not unbridled, especially when compared to the pipeline business. It's cyclical. Prices fluctuate. And long-lived means 10 years. There's a constant need to replace reserves and to muster the fortitude to weather the downturns.

For the stock trader with a 12-month time horizon, these are not problems. But in trying to continue a 100-year tradition of growth, pipelines in the storage fields that will generate income for 100 years to come are a much more stable foundation. But we need the balance provided by E&P. Operator, at this point, I'd like to take questions.

Yes, sir.

[OPERATOR INSTRUCTIONS] Your next question comes from the line of Jim Harmon of Lehman Brothers. Please proceed.

Hi, good morning.

Good morning.

Two quick questions. The first is, was the deferred tax adjustment at Seneca part of your original guidance?

No.

Okay. Second question is, is part of the Pennsylvania rate filings, are you going to try to get some sort of of a rate mechanism adjustment, i.e. at WNA for margin decoupling?

Absolutely.

Are you getting any -- do you have a sense for how responsive or how receptive the regulators may or may not be at this time. I think you indicated the New York folks had some learning curve to go up.

In the Pennsylvania trackers or revenue decoupling mechanisms have always been difficult, Jim. But with the change in the market and the high commodity prices that we're seeing, we think we have at least a shot of coupling our request for a revenue decoupling mechanism with a conservation program to make us relatively indifferent to continued conservation by the customers and it's in fact something we want to encourage for the overall energy usage of the country.

Okay, thanks -- I'm sorry, go ahead.

It's certainly not a sure thing, but we feel it's more achievable this year than it has been in the past.

Okay, maybe taking a 20,000 foot view, do you think the regulators in general have maybe a changed opinion as to what your responsibilities are to the consumers and what the regulator's responsibilities are to the utilities and maybe making sure they're financially able to serve their consumers?

Well, from a 20,000-foot view --

This has been a difficult period for everyone, and so this is just not a company-specific issue.

Right. I think, certainly, from the [NAYROK] point of view, [NAYROK] has actually come out with a policy statement encouraging revenue decoupling, but as with any large group, there's always differences of opinion between the individual members, and you're right, as I had indicated before, our initial discussions with the New York Commission were not -- let's say, they weren't jumping for joy for us coming in with that type of a mechanism. Because one of the things that they're interested in doing is actually tying the, I guess, the benefit from that type of a mechanism to efforts that the company actually undertakes. And the struggle there was that there was some conservation undertaken by the customers just as a result of high gas prices, not with respect to any efforts that the company undertook. We're having ongoing discussions there and I hope and I expect that as more of these mechanisms come into place all across the country and we're seeing more and more states, there's about 10 of them now that have them, that it's going to be an easier job for us to incorporate them in New York and Pennsylvania.

Great. Thank you.

ur next question comes from the line of Mike Heim of A.G. Edwards. Please proceed.

Good morning. Two quick questions. One kind of specific and one more general. I'll do the specific one first. And that's on the West Cameron 213. If I go back to the slide you very often use on expiration and exploitation opportunities, I don't see that in there. Did that have a different name, or was this something that was just added, drilled recently?

That was supposed to be East Cameron, not West Cameron. That slipped through as a mistake there. So that's the East Cam 213. And that was a one-well field that we had drilled last year. So we anticipated it would already be on production, but that's why it wasn't. I'd have to go back and check that slide to see if that East Cam was on there.

I don't see it, I see an East Cam 34 number 1.

Right. So it was $4 million a day so that was just one that was probably on the '05, we had drilled it, added reserves, and thought we'd have it on sooner.

And the more general question is on the pipeline projects. I'm just kind of trying to think through the Rockies Express. Assuming that goes all the way to Pennsylvania and maybe even does a leg up to Lighty, how do you guys think that affects the Millennium pipeline and/or some of your projects?

Well, it's really I think two different timetables, for one thing. But for the extent that it comes up to Lighty and then we can use that to move gas through our system up to Millennium, I think it's a positive for incremental projects. I don't think it has any impact on the Millennium project or a connector presently or in the immediate future. But over time, I think we've been saying right along that the great significance to Millennium is to open up a path to the east or an additional path to the east, and particularly our Tuscarora extension would enable us to connect the heart of your pipeline and the storage system to east coast markets and part of that system is the existing facilities we have from Lighty, which would then be able to be connected to Millennium and move gas from Rockies Express over to New York City that way.

Okay.

Because of our position, the more gas that moves around in this area, the better off we are. It creates storage opportunities, it creates transportation opportunities, it creates opportunities to expand the throughput on our existing facilities and just make them more valuable.

Yeah, Mike, we're looking at a number of storage products. In that general geographic area. As we see it, there's only upside with regard to that pipe and a number of others that are proposed. Utilizing our geographic -- our geographic footprint, so to speak.

The Empire Connector, would you be able to sign long-term contracts with that?

The connector really isn't designed to move gas in the appropriate direction to take advantage of the Rockies Express. The connector's up in the northern part of our system, whereas Lighty is in the southern part of our system.

That's kind of what I'm going at. If the Rockies kind of floods Lighty with lower-priced gas and lessons the demand to move gas from Canada down. I certainly agree with what you're saying about the gas flow.

One of the beauties of the pipeline business, and this is a very significant advantage compared to the LDC business, is that you can move gas and there's reason to move gas both ways through the same pipe. So that if in fact Lighty is flooded with cheap gas, which may or may not be the case, but if in fact it is flooded with cheap gas, then we could probably use the connector or others of our facilities to move gas into Canada.

Okay.

If suddenly gas at lighty is markedly cheaper than gas in Canada, then we'll move the gas into Canada.

Well, Mike, that's why, for us, the Millennium project itself is so critical to clear gas out to the markets on the east coast.

Isn't Transco doing the expansion to move stuff east? How does that compete with Millennium?

It exactly competes with Millennium. I think the east coast markets are big enough for everybody.

Okay, thanks for your thoughts.

[OPERATOR INSTRUCTIONS.] Your next question comes from the line of Michael [Scrag]. Please proceed.

Could you touch on the hedging penalty in the last quarter, and also with the success of the 48 successful wells, how does that affect your production profile next year?

Well, the hedging, the biggest component of that hedging is the oil hedges that are in there. And so as you know, we've decided the basis differentials in California to more or less go unhedged in our California oil production. So what we see going forward is a just continuing to improve. We think that the oil markets are very strong. That we will see very good prices on the oil side for next year. I think next year's NYMEX trip is still over $70, and we're essentially in an unhedged position until we can identify a way to lock that basis in California. And we are actively pursuing and trying to identify a way to hedge the California production and lock in that basis. But right now, the basis continues to improve. It's about $12 for the heavy oil. And we will expect to see some very strong prices next year. And with the minimum amount of hedging expense associated with that oil.

If the question is, how much did hedging impact or realized prices, you can see that on page 19 of the press release. The weighted average gas price without hedging was $8.37, the weighted average price after hedging was $7.39. For oil, the comparable numbers are $54.37 and $40.30. So on gas it was about $1.00 and oil it was about $14. With respect to our production profile for 2007, we have not yet given any indication of what our expected volumes are for 2007. I'm not sure that our profile, per se, is going to change as a result of these wells. I don't think it's changing our mix of long-lived wells and short-lived wells, significantly, if that's what you mean by the question.

Thank you.

Your next question is a follow-up from Jim Harmon of Lehman Brothers.

Thank you. I just wanted to ask a little bit about the acquisition you made in California. It looks like it's adjacent, well, it is adjacent to your existing properties, but are there other, sort of bolt-on acquisitions you're evaluating, and maybe we should be looking for those as the year progress?

Well as I've indicated, we're out there actively pursuing and looking for these kind of, as you say, bolt-on acquisitions on adjacent properties. There are a number of people out there that might be interested in selling, it's whether or not you get to a price that both the buyer and the seller can agree on. But that is one of the arenas that we are looking at, because we think that's a viable opportunity right now.

Is this just in California or are these in all of your regions?

We try to identify something all the regions. We would like gas, but we're going to go where the opportunities are, so we try to identify acreage that's close into our production where we can minimize the impact on operating expense.

Thank you.

[OPERATOR INSTRUCTIONS.] There are no more questions at this time. I apologize -- there is a follow-up question from Michael [Scrag]. Please proceed.

Yes. Could you just touch on your buyback year. You indicated that would be complete by January 2007. Was that a typo in the report?

No. Based on the rate and the volume limitations we have under 10B-18 of the SEC rules, at the rate that we expect to accomplish that, that's when we expect it would be done.

That's roughly eight months' time?

Yes.

Okay, thank you.

There are no more questions at this time. I would now like to hand the conference back over to Miss Margaret Suto. Please proceed.

Thank you, Amanda. We will now conclude our call. We would like to thank everyone for taking the time to be with us today. A replay of this call will be available in about one hour on both our website and by telephone and both will run through the end of business on Friday, May 12th. Our website is www.nationalfuelgas.com. The 1-888-286-8010 using pass code 80957234. We look forward to seeing many of the you at the AGA conference this weekend and this will conclude our call for the day. Thank you and good-bye.

This concludes the presentation. You may now disconnect.