National Fuel Gas Co (NFG) 2003 Q4 法說會逐字稿

Good day, ladies and gentlemen and welcome to the Q4 2003 National Fuel Gas Company earnings conference call. My name is Jean, I'll be your coordinator for today. At this time all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of the conference. If at any time during the call you require assistance, please press star followed by zero and a coordinator will be happy to assist you. As a reminder, this conference is being recorded for replay purposes. I'd now like to turn the presentation over to your host for today's call, Mrs. Margaret M. Suto. Ma'am, you may proceed.

Thank you, Jean. Good morning, everyone. Thank you for joining us this morning for a discussion of last evening's earnings release. Today's presenters are, Philip C. Ackerman, Chairman, President and Chief Executive Officer of National Fuel Gas Company; Joseph P. Pawlowski, Treasurer of National Fuel Gas Company; and James A. 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 must 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 Gas Company's Form 10-K on pages 57 and 58 of the 2002 annual report for a listing of certain specific risk factors.

And with that, we will begin the discussion with Joe Pawlowski.

Thank you, Margaret and good morning, everybody. The fourth quarter of our fiscal year is generally a quiet quarter from an earnings standpoint. With a summer losses and the regulated utilities in the U.S. and the Czech Republic, generally offset by the earnings of our pipeline, E&P and Timber segments. The fourth quarter of fiscal '03 pretty much followed that pattern except for two major transactions.

The first major transaction was a sale of about 50% of our Timber holdings which closed on August 1, 2003. The proceeds from the sale of approximately $186 million were used to pay down short-term debt borrowings associated with the purchase of the Empire State Pipeline and we recognize about $102 million of earnings. The like kind exchange tax treatment on the sale of the Timber allowed for the deferral of the income tax on the gain to be paid in future years providing more cash today to pay down debt.

The second major transaction that occurred in the fourth quarter was the sale of the southeast Saskatchewan Canadian oil properties. The net proceeds of $76.4 million were used to pay down debt and we recorded an after-tax loss on the sale of $39.6 million. Now, the loss is lower than the range we had initially estimated of between $50 and $60 million due to getting a better tax answer and a higher currency translation gain.

The impairment of the Canadian full cost pool was computed after the sale of the oil properties, and was to a certain extent affected by the sale due to the fair value methodology of allocating the investment in the full-cost pool between assets sold and assets retained. In addition, commodity prices at September 30, 2003, were down from the third quarter. Bottom line, at September 30, the present value of the future revenue stream of production equals the full cost pool investment. Obviously, the successful ongoing Canadian exploration program and resulting reserve additions is key to avoiding a future impairment.

So with that introduction, I have a few comments in our fourth quarter's performance. As noted in the earnings release, earnings for our fourth quarter of 2003 on a diluted earnings per share basis were 71 cents per share compared to 6 cents per share in the prior year. The increase in earnings was attributed to the net gain on the sale of assets just mentioned. Excluding nonrecurring items, consolidated earnings for the fourth quarter fiscal 2003 were 3 cents per share compared with 5 cents in the prior year's fourth quarter. Pages 7 and 8 of the earnings release provide a reconciliation of earnings before nonrecurring items to reported earnings in both dollars and earnings per share.

The information provided in the quarter earnings release is quite detailed but I have a few additional comments for the quarter. In the Pipeline segment, earnings are down slightly for the quarter. The Empire State Pipeline added about $1 million of earnings this quarter, however, those earnings were offset by lower earnings in our Supply Corporation due primarily to our higher effective income tax rate. The tax rate this quarter was 41% as compared to 26% in the prior year.

Although Supply Corp's earnings were down, efficiency gas revenues for this year's fourth quarter were $3.8 million, an increase of $1.7 million over the prior year's fourth quarter. The increase in revenues is a result of higher gas prices. For the fiscal year, efficiency gas revenues amounted to $15.6 million, an increase of approximately $6.6 million over fiscal 2002. Volumes for the year were up about $90,000 Mcf with higher gas prices, the principal driver for the revenue increase.

In our E&P segment the lower effective income tax rate referred to in the quarter's earnings discussion relates to our Canadian operations and the ability there to take advantage of tax loss carry-forwards to reduce Canadian income tax expense. And again, these comments are exclusive of the tax effect on the loss of the sale of Canadian properties and the impairment. And Jim Beck will provide more details on this segment in a few minutes.

During fiscal 2003, we were able to accomplish a number of objectives. We increased our investment in regulated assets where we have a proven track record of earning very good returns. We were able to purchase the Empire State Pipeline by selling Timber assets for a significant profit and we avoided selling additional shares of common stock. We sold nonperforming Canadian oil properties, we reduced the total amount of debt outstanding in our balance sheet during fiscal 2003, and we increased the equity component of total capitalization including short-term debt to 43% at September 30, 2003, up from last year's 39%, and we remain committed to strengthening our balance sheet and raising our equity component to at least 50% of total capitalization.

Regarding earnings guidance, during the third quarter's conference call on July 31, we provided some very broad earnings assumptions by segment for fiscal 2004. A range of earnings provided at that time was $1.70 to $1.80 per share before the one-time expected charge relating to pension obligations.

We are reducing the fiscal 2004 earnings expected range by 5 cents per share due to the expected conservation of gas usage in our New York retail jurisdiction due to higher gas prices. We used a number of forecasting tools and based on the results of the modeling, usage per residential account is expected to be lower in fiscal 2004 by about 4 Mcf per account, to 113 Mcf per residential account. This computes to about two Bcf in expected sales loss during fiscal '04.

Using the same modeling our Pennsylvania retail division's retail customers appear quicker to react to gas price increases and their conservation efforts began showing up in fiscal '03 so we see only a small effect in fiscal '04. The residential customers in our Retail Marketing segment are less inclined to reduce consumption. As a result, the company is revising its previously disclosed fiscal 2004 earnings per share guidance from $1.70 to $1.80 per share, to $1.65 to $1.75 per share excluding nonrecurring items. Including the impact of an expected one-time charge relating to pension obligations, earnings are expected to be in the range of $1.55 to $1.65 per share.

In a rate making arena the New York commission approved a one-year settlement agreement for fiscal 2004 on September 18 of 2003. The essence of the settlement is that rates remain unchanged. In our Pennsylvania rate case, we reached settlement with all parties to increase rates by a modest $3.5 million. What's more important and what was our main objective in filing the rate case, was to obtain a rate tracker for pension costs.

All parties agreed to allow the company to defer the difference between the amount of pension costs included in revenues, and the contribution made to the pension plan. Any differences will be deferred to the balance sheet for subsequent recovery or a refund to rate payers through a formal rate proceeding. We expect the commission will approve the settlement in December of 2003, and rates go into effect January 15, 2004.

Looking at the earnings for the first quarter of fiscal '04, we expect earnings to be in the range of 45 to 55 cents per diluted share, excluding nonrecurring items. Including the one-time charge relating to pension obligations, earnings are expected to be in the range of 35 to 45 cents per diluted share.

Now I'll turn it over to Jim Beck.

Thank you, Joe. And good morning everyone. Seneca's fourth fiscal quarter for 2003 finished with strong commodity prices and as you've heard, Seneca closed its sale on the southeast Saskatchewan oil properties. Since the sale closed at the end of the fiscal year, the production for the quarter of 17.1 Bcfe included the production of approximately 2.7 Bcfe from the properties that were sold.

We detailed the reasons behind this sale in our last quarter's teleconference. The press release from yesterday summarized the results. We are not pleased with selling this asset for a loss. However, given the high oil prices, we felt it was an opportune time to cut our losses on these properties and move forward exploring for natural gas in Canada.

There were two nonrecurring charges associated with the Canadian sale. The fiscal summaries that follow will exclude these nonrecurring charges. For the sale in Canada, the after-tax loss was $39.6 million, the after-tax impairment related to the Canadian properties was $6.3 million. The NYMEX prices used in Canada as of September 30, 2003, that related to this impairment, were $29.20 per barrel for oil, and $4.83 per Mcf for gas.

Summarizing a few key financial highlights of the fourth quarter, oil and gas prices, after hedging, finished strong at $21.93 per barrel and $4.59 per Mcf. This was a 2% decrease in oil prices over fiscal 2002, and a 21% increase in gas prices. This helped offset the 17% year-on-year production decrease for the quarter. The production decrease reflects primarily the high decline rates and erratic production associated with offshore, where we are gradually phasing out of that activity, and the oil decline rates of the properties that were sold.

Year-on-year quarterly revenues decreased 9% to $71.6 million, and Seneca's net income was $7.1 million or 9 cents per share excluding nonrecurring items. This was an increase of 62%, over 2002 levels. Higher gas prices combined with a lower effective tax rate and lower DDNA and G&A expenses were the primary reasons for this improvement.

Looking at fiscal 2003, Seneca drilled a total of 149 wells with a 94% success rate. While the number of wells drilled were lower than expected, primarily because we suspended development drilling in southeast Saskatchewan, the total capital expenditures were also lower than expected at $75.8 million. This lower spending allowed Seneca to pay down more debt. When combined with the proceeds from the Canadian sale, Seneca paid down nearly $140 million in debt in fiscal 2003.

Breaking down the drilling in more detail, most of the drilling for the fourth quarter was in Canada and the East Division. A total of 42 wells were drilled with 100% success ratio. In Canada, 18 wells were successfully drilled and are in various stages of completion and production.

Looking at fiscal 2003, total drilling is as follows: 52 wells drilled in Canada, 51 wells were drilled in our East Division, 31 wells were drilled in our West Division and five wells were drilled in Gulf Coast. The key exploration success this year was in our Gulf Coast. Seneca drilled three blocks that were part of the transition program and they were all successful. All three of these wells will be on production by November 1 of 2003. The most significant well was our Highland [ph] A-345 No. 1 well. This well was expected to produce approximately 15 million cubic feet per day and Seneca's working interest is 100%.

The fiscal year results had a number of bright spots. Despite production dropping 15%, revenue declined only 2% to $305.3 million. G&A, LOE and DDNA expenses were all lower than they were last year. Net income for the year, excluding nonrecurring costs was $37.3 million, or 46 cents per diluted share. That is a 39% improvement over last fiscal year.

In reviewing 2003, while actual cash expenses were lower in every category, the expenses per Mcf was not. DDNA came in very close to last year's guidance at $1.34 per Mcfe versus guidance of $1.36 per Mcfe. LOE came in higher than forecast at 97 cents per Mcfe versus guidance of 87 cents per Mcfe. This increase was primarily due to increased California steaming costs related to higher natural gas prices. G&A was 2 cents higher than guidance at 29 cents per Mcfe.

Looking ahead to fiscal 2004, now that the Canadian sale is completed, the allocation of the full cost pool and related impairment charges has changed our DDNA forecast for 2004. Our original guidance for 2004 was $1.56 per Mcfe, the new guidance is $1.47 per Mcfe. In addition, G&A has changed from 40 cents per Mcfe to 43 cents per Mcfe. And LOE including taxes has increased from 89 cents per Mcfe to 93 cents per Mcfe.

Seneca's production for fiscal 2004 is still expected to be in the range of 57 to 62 Bcfe with gas accounting for 55% of that production. This is approximately a zero to 8% decrease in production from our 2003 levels, after an approximate 12 Bcf reduction for the Canadian properties that were sold. It is expected that the first quarter's production will be in the range of 14 to 16 Bcfe.

Seneca's hedging has changed slightly since our third quarter teleconference. A summary of all the hedged positions for 2004 is as follows: 13.7 Bcfe of gas is hedged at an average price of $4.53 per Mcf, and 2.9 million barrels of oil hedged at an average price of $26.46 per barrel. A detailed breakdown of all these hedges can be found in the press release from yesterday.

Now, looking at earnings sensitivity after hedging, to price changes is as follows: Raised 25-cent change in the average yearly gas price, earnings will change by 5 cents per share, and for each dollar change in the average yearly oil price, earnings will change by 2 cents per share. Our goals for 2004 have not changed. We will live with in-cash flow and pay down debt, second we'll continue to work to grow Seneca by the drill bit, our goal is still in place to replace 150% of production with the finding and development costs of nearly a dollar.

We have a number of excellent prospects to be drilled this year and we'll keep you advised on their progress. And lastly, we'll continue to reduce expenses to track our lower total production.

So at this point, I'll turn it over to Phil.

Thank you, Jim. The year-end sale of our Saskatchewan oil properties capped off an extraordinary year for National Fuel. We expanded our pipeline in the storage business in terms of investment, in terms of new market opportunities, and in terms of new growth opportunities.

The acquisition of the Empire pipeline will prove to be an important strategic fit in the years ahead. Our investment there was about $180 million in cash, plus an assuming $60 million in debt. We monetized about half our timber, for $186 million. The opportunity to utilize a tax advantage strategy was a key element in enabling to us acquire Empire and improve our balance sheet without issuing equity. This also should give the market an indication of the value of our remaining timber and the potential for value in that business.

We acquired the total landfill gas systems. We were pleased with our results in the small investments we had made in the landfill gas area and Toro seemed to be an excellent opportunity to utilize our existing skill set in gas handling in a developing line of business. Our investment there was about $48 million. And finally, we sold our southeast Saskatchewan oil properties. They simply were not what we thought they were going to be so we took the loss, took the cash and paid down about $76 million of debt.

At the same time all this was going on, we achieved record earnings with strong performances from our historic asset base. Including the Utility, Pipeline and Storage, Marketing, and Timber. We wrote off the goodwill in International and absent that, it, too, improved although it continues to lag the performance our other segments.

While we made four strategic moves in 2003, significantly improving our future, it is unlikely that we will achieve record earnings as soon as 2004. While Empire and Toro will have a full year to contribute to earnings, significant expansion of Empire, although likely, cannot occur for at least two years. And while we have a lower risk, high probability drilling program, the longer lived reserves which are our primary targets, will be unable to quickly offset the decline of our Gulf of Mexico properties or make up for the properties we sold. Similarly, although we continue to focus on efficiency opportunities in the Pipelines and the Utility, it is difficult to match the benefits of a colder than normal winter.

With the moves we have made, I'm extremely optimistic about our future. But the best of our future is two to three years away. In the meantime, we remain committed to our dividend and alert for opportunities. With that, Operator, we're ready to take questions.

Thank you, sir. Ladies and gentlemen, if you wish to ask a question, please press star followed by one on your touch-tone telephone. If your question has been answered or you wish to withdraw your question, press star followed by two. Questions will be taken in the order they are received. Please press star 1 to begin. First question of the day comes from Donato Eassey of Royalist Research. Please proceed.

Good morning, Phil, Jim, Joe, everybody and Margaret. Phil, I just wanted to get a feel for the E&P effort, you mentioned that the CAPEX was down below budget this year and, Phil, you just mentioned that it looked like you weren't going to be able to keep up with the decline curves but is there any prospect out there that could change that anytime soon? Or would that be just too optimistic? And, Phil, secondarily, given what you have left in timber and the prices you got for it, what do you envision there as we head into '04/'05? Thanks.

Okay. Donato, as Phil stated, we are shifting to drilling for long lived reserves and typically those wells come on at lower rates. But we do have a couple of nice offshore prospects, as we said we're transitioning out of the Gulf and we're still looking to drill some of the better quality, shallower prospects that we still have in inventory. So we're not totally out of the Gulf.

We think we've got a couple of real nice prospects. And we will drill those. And if those were successful, that would definitely be a significant improvement in our production going forward for the year. But we did not include those in our forecast. Because it is exploratory. But we are going to emphasize long-life reserves drilling more wells. We've been very successful in east, we've seen a number of quality areas and have a extensive program to drill. And we'll be very active in drilling these shallow wells there. We have a number of very nice looking exploration prospects in Canada that we'll be drilling this year. Any one of those could significantly impact production.

So, while we are forecasting a 0 to 8% decrease after the sale, there are some significant opportunities out there that could provide some upside to those numbers.

Thanks, Jim.

Denato, this is Phil. I think clearly we do have some significant potential on the E&P side. The difficulty with respect to having a major impact on 2004's results is, we're already a month into 2004, it take a certain period of time to get these things drilled and on line and so forth. And, even though you may have great daily production rates, with every passing day, you have fewer days left in 2004. They're more likely to have a very nice impact in 2005 when you could have a full-year's production. But we do have some very good prospects.

On the timber side, we still have about half of our timber left. We realized a very nice price for the half that we sold. But as you know, I'm very pleased with our timber operations. And I see no reason to sell the remaining timber operations, absent some attractive alternative. And it worked out very well with the Empire Pipeline acquisition where we had the opportunity to acquire something that's a great strategic fit, as I said, it's close to home. We had the opportunity to effectuate the sale and the acquisition on a tax-advantaged basis, and so the confluence of events made the timber sale an advantageous and logical thing.

Without some confluence of events like that, I don't see any particular reason to sell the timber merely to pay down short-term debt that's remarkably cheap at this point in time. The timber business has been good to us, and I'd welcome the opportunity to expand it on favorable terms.

Thanks, guys.

Your next question comes from Doug Christopher of Crowell, Weedon. Please proceed

Hi, thank you. There seem to be lots of moving parts and different, I guess, distractions. You've got a great utility business, and a good A&P business. Why even continue in the diversified operations? It seems the last year and a half, two years, that things like International, they're just a continual distraction and leave more room for disappointment than anything. Why not just focus on the core Utility and the E&P operations?

When you refer to core Utility, I hope you're including the Pipeline and Storage?

Absolutely.

Yeah, okay. Because the Pipeline and Storage has been consistently our best performer.

Yeah. But International and Timber.

Well, to take it in reverse order, Timber's been a great business for us. We made a lot of money on that on a relatively small investment. It's a great hedge against inflation, people don't worry about inflation too much these days. We have a very good position there. And it doesn't take a great deal of senior management time to manage that. The trees have the ability to grow all by themselves out there. On the other hand, we do have professional foresters that watch over the whole thing. So we don't ignore it.

International is a tougher thing. And we continue to have discussions with potential buyers in that arena. We're not compelled to get out of that area at a distressed price, but it does seem that it's not a particular strategic fit for us.

All right, thank you.

Your next question comes from Rebecca Followill of Howard, Weil. Please proceed.

Good morning, a couple of minor questions and then one macro. On International, what's your book value in that asset? What is it on the books for?

We've got people looking here for a minute, can you give us a minute?

Sure, let me get to the other one. On your deferred taxes for the timber properties, how much is that deferred tax? And then while you're looking for that one, too.

People understand the question, we're just scurrying to make sure we get the right numbers.

Yes. That's fine. The other one is on the Canadian property, how much of your full-cost pool, of the main full-cost pool is Canada? So that in the event we were to see prices decline further, there's probably additional write-downs to take, how much of the pool that's left is Canada? And then while you're looking for those let me ask the big picture question. Back on E&P, if you look at this year, you spent $76 million, your finding costs were about 230 and then you were placed, it looks like less than half or -- yeah, less than half of your production. Your goals for next year are to replace 150% of production and have S&D costs of $1. Can you go through more specifically what changes between '03 and '04 to have that big swing? Is part of it due to these three wells you drilled in the Gulf that are coming online November 1, are part of those reserves booked in '04? Can you help us out with what really causes that swing?

Jim has some detail on that, but in a nutshell, a lot of our expenditures in 2003 were for PUDs. I other words, the drill reserves that were already on the books and for facilities. But I'm going to leave it to Jim to deal with more of the detail of that.

Rebecca, the few key points there, last year was really a major transition year for us. Shifting with the sale of the Canadian properties, and with the emphasis of moving towards exploration. We really cranked up the exploration component of our program last year. And we're going to see the benefits of that this year. We're going to see a lot better quality prospects that will be drilled and so that's why we think we're going to see an improvement.

Back when we were primarily an exploration back in '99, our finding and development costs were 83 cents. And we think we can get back to that level again with our emphasis on going around and drilling these quality exploration prospects that we see, both in a few of them that are left in the offshore plus what we're going to be drilling in Canada and in the northeast.

Was part of the cost then for '03 related to seismic or costs that will bear fruit in '04?

Right. There's the capital dollars that we spent when you look at what we spent last year just in facilities and in the drilling of PUDs, was something on the order of, I think it was $17 million. So all of those dollars, they did not contribute any new reserves. What we did do is we did spend money on the seismic, as you said, trying to identify these new plays. We also, as part of our ongoing program in transitioning out of the Gulf spent a lot of time working on farm-outs. We've got one program where we've got one company committed to drill two wells on one block, both of them below 16,000 feet where we have a carried interest. So there are a number of things that we're doing that are going to significantly improve the opportunities for us in 2004.

Okay. Thank you.

Rebecca, as I recall the questions here, the first one was what is the International segment on our books for?

Yes.

That's about $134 million.

Okay.

The second one was the amount of tax that was deferred in connection with the timber?

Yes.

That's about $50 million.

Okay.

And the third one was the amount of the Canadian full-cost pool?

Yes.

And that's about $118 million.

Thank you so much.

The full cost accounting treats the Canadian assets separate from the U.S. assets, so they're two separate full-cost pools.

Okay. Great.

With the value of the Canadian one measured and then the value of the U.S. one measured separately.

Thank you.

Your next question comes from Jay Yannello [ph] of UBS. Please proceed.

Good morning. First of all I want to welcome Margaret back.

Thank you, Jay.

After that, Jim, kind of following up on Denato's question, I realize there's some upside in production and that is good. What could go wrong where we could see a slippage? Or looking at it another way, is that really a pretty bear-bottom number you are kind of putting out at this point.

Yeah, that number that we have out there is more or less the see, feel and touch number from what we've drilled and identified in 2003 and just going forward. We have very little in the way of exploration reserves looking forward into 2004. So we feel fairly comfortable that that is a solid range we're dealing with right now.

Okay. And I might have missed it but on the pension, there's a charge coming next year. Can we have some of the updated numbers on the pension, what it's funded at, and what it will be funded at? Any other information on that will be helpful.

We're looking in the next few years to fund between $35 to $38 million into our pension fund per year. And we do have this special charge that we're looking at that will probably occur in the first quarter, and it relates to special termination benefits. Not the ordinary year-to-year pension type obligation.

Were you looking for the full editorial discussion of the pension with all the assumptions and so on? We can get that out.

No, I can look that up. I guess what is the special termination charge regarding?

As regard to the settlement of accrued benefits.

Okay.

There's more desired accounting that's associated with the current recognition of actuarial gains and losses in proportion to the amount of benefits that are being settled out on a cash basis.

All right, that's fine. Let's just end it there.

That's about as far as I can go. Then you get into the accounting of it all.

I'll yield the phone. Thank you.

I would like to say on the amount of the production, that we pressed our guys in Houston pretty hard on that to make sure we had numbers that we felt comfortable with there. It seems to me that what we're exposed to are sort of physical risks, things like hurricanes and so on. Which you can't predict. We know there will probably be some degree of shut-in for hurricanes but who knows how many hurricanes there will be in any given year. It seems to me that's the largest risk with respect to those production numbers.

Okay. Thank you.

Jay, just a quick follow-up there, it looks like the exploratory reserves that we're looking at for next year are right around 5% of total production. But we don't have a significant piece. And we define exploratory here as reserves that are not booked. And since we're not drilling any PUDs in East, all that production that we drill there is what we consider exploratory or new reserve adds.

Okay. Thank you.

And your next question comes from David Maccarrone of Goldman Sachs. Please proceed.

Thank you. Jim, I was wondering if you could give us a sense for what oil and gas prices support the U.S. and Canadian full-cost pools?

Okay. As I said, the Canadian September 30 price that was used was the number I gave you in the presentation, and that number -- let me find it here -- was $29.20 per barrel for oil, and $4.83 per Mcf for gas. And that was the NYMEX equivalent that was used on September 30. That was the same number really that would be used for the U.S.

If I'm right, maybe I don't understand this, but in Canada, if prices were to fall below those levels, given no change in reserves you might be subject to a write-down; is that correct?

Yes, that is the basis on which we're working off of so you're correct, if we saw that drop, that would impact us. Now the one thing to remember there is that we're primarily, since we sold all the oil properties, we're predominantly a gas properties now. The key number that's going to drive us in the future is gas. Now, we have the opportunity to add some new reserves with exploration, and so as we add new reserves with exploration, that will tend to lower that number. But you're right, initially that $4.83 number is the basis we'll be working off of.

What would a comparable number be for the U.S.?

Well, I think that was the NYMEX price as of year-end.

Do you want the number that we use for the test at year-end, which was $4.83 and $29.20 or are you looking for the number below which prices would have to fall in order for us to have a U.S. write-down?

The latter.

Okay, I don't know if we have that number.

Okay. Jim, also to follow up on the High Island prospect, is that currently producing? What sort of production have you assumed in your '04 guidance?

That property is expected, as I said, to come on about November 1, they're finishing the hookup on it right now and we expect first production to be right around November 1. That's a sub-C completion and being hooked up to another platform. And it's being completed as we speak.

That's supposed to have initial production of 15 million a day?

That's correct.

And what would the contribution in total be roughly for '04 from that?

That would be -- well, you're looking at -- that zone had 120-foot of pay and we feel it would be a contributor throughout the year. Just ballparking an estimate, because I don't have the exact production forecast in there, but you can figure that's about close to half a B per month for 11 months. So a little bit lower than that once you take out royalties. So .8 times that.

Okay. And shifting to Joe for a second. Joe, I was hoping you could shed some light on the Pipeline growth strategy, it also put into context the '04 outlook with that growth strategy. Looking at Empire, and then looking at the core National Fuel business, I'm trying to understand, it looks like your expectations going back to the July call are a little bit lower than your expectations were going into '03 for '04, I am assuming efficiency gas revenues and other items account for that. But when do we start to see the growth out of these businesses that the Pipeline businesses, and what sort of growth is it a couple percent a year or is it going to be more meaningful? And when do you expect to see projects like Millennium come into play?

Let me take the first part of that or maybe it's the last part, as we sit here with Empire, for us to build a new project, we're looking at at least a year of regulatory preparation and decision making and hearings and regulatory lag, and then another year of construction. Which is why I said that while I was optimistic about the growth opportunities in connection with the Pipeline business, I expect that it would be at least two years before we saw Empire actually able to have a significant expansion.

There are a variety of reasons for my optimism with respect to the growth of the Pipeline business. I've talked about that on other occasions, but fundamentally it has to do with the experience that the utilities and the commissions have had the last couple of winters where the marketers have in many cases failed to serve the residential customers. And the commissions are realizing that the utilities need to be the suppliers of last resort, and that the utilities need to maintain substantial amounts of pipeline capacity and storage capacity, and supply contracts in order to adequately fulfill their obligations as the suppliers of last resort.

It's been those kind of contracts that have been the financial underpinnings for the development of almost all the pipeline and storage projects in the United States. But I think we're coming back to the point in time where people are concerned about capacity, and the commissions are willing to let the utilities step up to long-term contracts in order to provide the stability of returns for those pipeline projects. So it's going to take us two years anyway to get anything through. Joe, I don't know whether you have any --

In terms of '04, the expected earnings from the Pipeline we certainly have reduced the efficiency gas revenues, I think I mentioned we were up about 90,000 Mcf this year compared to a year ago, and we've got lower prices in place for those revs. In addition, the FERC supply company does not have a pension tracker, we've got some increased pension costs there. I don't have that number readily at hand but those are two major items that would impact the earnings growth or lack of growth earnings for fiscal '04 compared with '03.

And going back to it, the original, if I've got my notes correct, the original rate base guidance for '03 was $423 million for the pipeline segment, and back in July I think you'd indicated $409 million. What accounts for that roughly 3% decline in rate base and what do you see going forward?

I think we have to get back to you on that. I don't think we have the numbers from a year ago here.

I don't.

Okay. Thank you.

Again, ladies and gentlemen, it's star 1 if you would like to ask a question . Thank you for your patience while we collect questions.

Jean, are there more questions there?

Yes, a question from Philip [inaudible] of CSFB.

Thank you very much. Just a couple of questions on the operating income line. The Utilities showed a large loss at least to what we were looking for, I was hoping you could give us some detail there as well as your thoughts for '04 -- I'm sorry, for the next year, fiscal '04?

Well, Phil, regarding '04, and I don't have the assumptions here at hand, but at the end of July, at the July 31 teleconference I provided rate base and expected returns on that rate base. And you would reduce the New York portion of a total utility return by the nickel that we just adjusted out, our earnings guidance downward by.

Okay. And that would have had the effect that we saw in the current quarter, the fiscal fourth quarter?

Could you explain what effect you're talking about there?

Well, no, on an operating income basis, the loss in the Utility was larger than the year ago quarter loss. And I was just hoping for some explanation or additional color relative to the additional $2 million impact that we saw in the reported numbers.

Yeah, well Phil, usually by the end of the year we true up our sharing arrangement in the New York position, and so we would have pushed through some utility rate true-ups that would have impacted the operating income for quarter four.

Okay. Thank you. Joe, on the call you give us some detail relative to the revised earnings outlook, and I appreciate that. Could you just add some color as to the other businesses, and was the entire impact from, as you described, customer conservation and, what I'm thinking is in looking at some of Jim's comments, which basically point to some successes in his outlook for '04, and recent hedging activity which appear to be at higher prices and higher volumes, which would tend to have a more positive or favorable impact to the overall earnings. So are we looking at a larger impact from customer conservation or could you just give us some additional detail how you're looking at the overall business?

Phil, the 5-cent adjustment refers just to the conservation effort that we see in our New York jurisdiction. The upside that Jim talked about is not reflected in our forecast in '04.

And do you think that maybe at the analyst meeting you may come back with some additional information? It seems like Jim's comments were quite positive in his outlook, and yet we're seeing an earnings reduction today. Is that being just overly conservative or do you see some other items relative to the operations of the business unit?

Phil, let me take a shot at that. Particularly with respect to Seneca, as I said before, we pushed those people in Houston pretty hard. I was frankly sick and tired of having us not meet our production estimates. I don't want to have that reputation as a company that doesn't come within at least a stone's throw of what we think we're going to produce and there's been downward revisions on our production estimates is something I don't want to see anymore. Maybe there's some upside there, I certainly hope there is. But what I certainly hope is that the estimate is biased on the downside and that we're going to make that number and we're not going to be coming back explaining why we didn't. I don't think I'm going to let them raise it up unless we've got an awful of lot of production online somewhere during the course of the year.

I appreciate that, Phil. As long as you have the microphone, just if you could add a little bit more color to your comment earlier on the call about the best of the future is in two to three years, and does that imply or should we take away from that that the next two or three years that we'll see flat earnings, but if you could just give us your thoughts behind that statement that the best of the future is two or three years away?

Well, it's based primarily on my enthusiasm for the Empire pipeline. I think that's a great acquisition for us. I think it's a great set, I think we bought it at the right time where we see the coming around on the part of the commissions to the notion that the utilities really do have a role in the future world and that that role is consistent with them entering into contracts for additional capacity. And the fact that it's going to take us two to three years to capitalize on that just because of the regulatory lag process and getting approvals and because of the physical length of time it takes to construct something.

And some of these other things, our strategy in the E&P business, getting away from the high rates of decline in the Gulf of Mexico into longer-lived reserves, working with longer-lived reserves it takes longer to build up your production and I think it's going to take us a while to get on a path of steadily increasing production based on long-rived reserves. The prospects in the Gulf of Mexico, I'm enthusiastic about drilling them, they'll be great returns on investment if we make some discoveries there.

But on the other hand, it just makes our problem worse, it will give us a pop-up in production that then will decline fairly rapidly that we're going to be chasing with these longer-lived reserves. I want to see National Fuel on a path of steady growth, and not one of spikes and falls. Not to say that I'm going to turn my back on these excellent investment opportunities, but I think it's two to three years off before we get on this path that I hope to be on of steady growth in our segment.

Thank you for that. That was great. But is the transition away from the Gulf drilling, is that on schedule or are we ahead of schedule there, are we going to see that exit sooner?

No, we're behind schedule. The fact is, when we come to this conclusion a few years ago, it was in the face of substantially lower gas prices. And with the higher gas prices, some of the prospects that we had identified and had in our back pocket some years ago that were not economic at that time, looked very attractive.

And if you run economics at $5 gas, it's a whole lot different from economics at $2 gas or $4 gas, and we've got the ability to hedge in now at $4. So there's not much reason not to drill those things that we really hadn't planned to drill, say, four or five years ago. So we're kind of behind schedule in terms of the phasing out, but we're behind schedule for a very attractive reason. Mainly that we've got prospects that suddenly became very economic.

Well, I appreciate your patience in answering all of my questions and I look forward to the analyst meeting in Jim's presentation, because I'm sure that he'll have some very good things to say based on your comments, Phil. Thank you very much.

Thank you.

Your next question of the day comes from Jim Harmon of Lehman Brothers. Please proceed.

Hi, good morning.

Good morning.

Regarding the Seneca reserves, 670 Bcfe as of September 30, is there any way we can get a regional breakout or is there any way we can get an idea of what the various RP ratios are per region?

Yeah. We can definitely provide all that data by region. Typically we have it put together on a summary basis.

We'll do that. We just don't happen to have it at hand. I think we generally have that in the slide presentations that we use in the investor conferences and at AGA. But it's not particularly a secret, we just haven't put that presentation together at this moment.

Okay. Well, how about a rough guesstimate as to what the various decline curves are? Or will you get back to me on that?

A rough estimate, Jim, you want to take a shot at that, 20%, 25% in the Gulf?

Yes. Typically what we see is we have an RP ratio, in fact, I can give you an RP ratio roughly for all the divisions.

Okay.

East, our East division RP ratios is 15.2, Gulf RP is 3.2, West is 21.9, Canada is 10.7.

Okay. That's all I need. Thank you.

We'll get the regional breakdown out shortly.

Sir, at this time I'm showing no questions.

All right, then I guess we will conclude our call, Jean. Thanks everyone for joining us today. A replay of the 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, October 31. Our website address is www.nationalfuelgas.com. The telephone replay number is 1-888-286-8010 using pass code 24135692. This concludes our conference for today. Thank you and good-bye.

Ladies and gentlemen, thank you for your participation on today's call. You may now disconnect.