National Fuel Gas Co (NFG) 2003 Q1 法說會逐字稿

Good morning, and welcome to the first quarter earnings teleconference. All participants will be able to listen only until the question and answer session of the call. This conference is being recorded at the request of the National Fuel Gas Company. I would like to introduce your first speaker for today's call, Ms. Margaret Suto, Director of Investor Relations. Ms. Suto, you may begin.

Thank you Chris, and good morning everyone. Thank you for joining us on the conference call for discussion of last night's earnings release. Today's presenters are Phil Ackerman, Chairman, President and Chief Executive Officer of National Fuel Gas Company; Joseph Pawlowski, Treasurer of National Fuel Gas Company, and James 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 form 10-K on pages 58 and 59 of the 2002 annual report, for a listing of certain specific risk factors.

With that we will begin the discussion with Phil Ackerman.

Thank you, Margaret. Well this quarter just proves once again what we all already knew, cold weather is good for the gas business. Earnings per share were up about 16 cents versus last year, and 10 cents of those 16 cents come from our Pennsylvania Utility operations, where we have null weather norm clause, and from our Explorations and Production segment, which benefited from higher prices. Another 5 cents came from International and Timber, and the remaining penny was from some pluses and minuses of a lot of little odds and ends.

The kind of consequential damage that we suffered from Hurricane Lili is disappointing. But on the other hand the changes in the industry, with Unocal taking over Pure, and the changes in our offshore thermo present us with the opportunities to drill two blocks ourselves. Which, coupled with the higher prices, give us an opportunity for significant improvement, with respect to fiscal '04 compared to what we were planning on.

The Empire Pipeline is moving along on track. Our last remaining approval that we require is from the New York Public Service Commission, which voted last week to give us that approval. However, we have yet to receive the written order, which would contain any conditions if there are any.

As I stated last quarter, we are exploring the sale of certain non-regulated assets as an alternative to issuing debt and equity for the long-term financing of that acquisition. While we have received favorable responses, particularly with respect to the sale of some of our Timber assets, we expect to finance the Empire acquisition in the short run using short-term debt.

In short, we have performed as you have a right to expect. Colder weather yielded higher profit. We have no operational problems with our system. We have no gas supply problems. Gas prices are higher, but they're not crazy, given the weather that we are experiencing. Specifically with respect to the weather, very recently we have experienced very cold weather with temperatures below zero here in Buffalo, Western New York and Northwestern Pennsylvania. We are looking forward to having a very good March quarter, as a result of the start that *we're off to this point.

With that I'm going to turn it over to Joe for some more details on the numbers.

Thank you, Phil, and good morning from frigid Buffalo New York. Yesterday when I woke up it was minus six degrees, and this morning about 10 degrees, so it's pretty darn cold, but it's excellent gas company weather. Some of the things I have to say may repeat some of those that Phil said, so I apologize for that.

We had a first rate quarter, as reported in our first quarter earnings release. Earnings before non-recurring items were 58 cents per diluted share, up 13 cents per share from last year's first quarter earnings of 45 cents per share. And to differentiate from Phil, this is before non-recurring items. The 13 cent increase in earnings is attributed to the following. First, was the colder weather we experienced this first quarter, particularly in our Pennsylvania Service Area. It was just over 34% colder than last year, and the colder weather contributed 2 cents of additional earnings over last year. Our New York division earnings were essentially flat with last year, there was no pick up in earnings due to the cold weather, because of the workings of the weather normalization clause.

Second our E&P segment posted earnings of 11 cents per share, 5 cents greater than last year. Higher commodity prices realized on the sale of production, more than offset lower production volumes. Oil prices after hedging increased by $3.71 per barrel, and natural gas prices after hedging increased by 81 cents per Mcf. Jim Beck will have some additional comments on this segment, in a few minutes.

Our International segment contributed 3 cents per share of earnings, up 2 cents per share from the prior year. New heat rates that went into effect this year, coupled with a 22.4 MWh increase on electricity sales, accounts for the rise in earnings in this segment.

Timber segment earnings increased by 3 cents per share, to 5 cents per share for the quarter. Higher sales of cherry logs and cherry lumber, which have the highest resale value, were the main drivers. All other business segments were essentially flat compared with last year.

Regarding fiscal '03 earnings, we reaffirmed our range of estimated earnings of $1.60 to $1.70 per share, even though our first quarter results were better than expectations for two reasons. First, although commodity prices are expected to be strong for the remainder of the year, this will be tempered somewhat by lower estimated production volumes. The second factor is the acquisition the Empire Pipeline. As Phil mentioned, we expect to receive an order from the Public Service Commission either this week or next. While we are pursing the sale of assets to help finance the acquisition of the Empire Pipeline, the current earnings guidance reflects the sale of approximately 6m shares of common stock.

For the second quarter of fiscal '03 we expect earnings to be in the range of 77 cents to 82 cents per diluted share. As I mentioned earlier, it's a great first quarter. Now I will turn it over to Jim Beck.

Well thank you, Joe, and good morning everyone. The first quarter of fiscal 2003 finished with strong commodity prices. Cold weather and a hurricane impacted our first quarter financial results. A review of the financial results is summarized in detail on page 13 and 14 of yesterday's press release. However, we would like to highlight a few key points, and then discuss a number of key operational changes that occurred during the quarter.

Our commodity prices after hedging, increase an average of 24%, while production was down 14%. This resulted in revenues, excluding the Enron adjustments, increasing 6%. This helped to propel Seneca's net income for the quarter to $8.8m, or 11 cents per share. This was 87% above 2002 levels. All our operating expenses came in close to forecast, and there were no major changes in our hedging positions for 2003.

Drilling proceeded ahead as planned, with 41 gross wells drilled during the quarter, with a 93% success rate. Our capital budget remains unchanged.

In the Gulf, Hurricane Lili did cause a significant amount of damage to other companies' facilities. This caused Seneca to lose some production during the quarter. Actual damages to Seneca's facilities were minimal. However, there were three wells that have not resumed pre-hurricane production levels. These will have an impact on our production forecast, which I will review shortly.

First, the changes in the industry that impact Seneca's operations were the Unocal acquisition of Pure Resources. Pure had drilled two successful wells out of three as part of a seven-well farm out program. Unocal has indicated they may not drill the four remaining wells that are part of that program, and they released seven other blocks from their commitment. As a result Seneca is reviewing these blocks that contain bright spot seismic anomalies, and we anticipate drilling at least two of them this year.

In our East division, Talisman, who acquired exclusive drilling rights to the Trenton/Black-River wells, on Seneca's 650,000 acres, has elected to terminate this program. They had drilled two wells during the program. This will allow Seneca to negotiate with other companies that are interested in drilling deep wells on Seneca's land, while we continue our shallow successful operations in New York and Pennsylvania. We expect to drill over 50 wells in our East division this year. The termination of this program will not affect our ongoing drilling program in Canada with Talisman. The second Monkman (ph) well is currently drilling.

In California, the spot prices for gas that we are using for Steaming, remains significantly below Nymex prices. The January spot price for gas used for steaming was approximately $3.27 per Mcf. Therefore Seneca is maintaining an aggressive Steaming program. In addition, we have finished 18 of the 31-well drilling program, and these wells are now in the process of being steamed.

Looking ahead to our expectations for the second quarter. We expect production to be between 18 and 20 Bcfe. Most of the decline we are seeing is in the Gulf. We anticipate drilling over 180 wells in both the US and Canada in 2003. But the production from these new onshore wells will not be able to offset the damage caused by Hurricane Lili, and the additional losses in offshore production. Therefore we are revising our 2002 production forecast downward, to a new range of 76 to 81 Bcfe.

Lastly, with these current high commodity prices, the question always rises of the impact of price changes on Seneca's earnings. Currently for each one dollar change in the average oil price, earnings will change about 2 cents per share, while for each 25 cent change in the average gas price for the year, earnings will change 4 cents per share.

At this point I will turn it back to Phil.

Christine, we'll go ahead and take questions at this time?

Thank you, Mr. Ackerman. At this time we'd like to begin the question and answer session of the conference. If you would like top ask a question, please press star, one. You will be announced prior to asking your question. To withdraw your question you may press star, two. Once again, if you would like to ask a question, please press star, one. The first question comes from Mr. James Yannello with UBS Warburg. Mr. Yannello, you may ask your question.

Good morning, two quick questions. Phil, if Timber was a possibility of -- a sale of Timber was a possibility - I know you guys have considered it in the past - is there any tax efficient way at this juncture that you've come across to be able to do that. The second question is, Jim, with this new production guidance, can you give us some parameters as to how comfortable you are with it? What could be the downside to it; what could be the upside to it? Thank you.

Jay, we are actively exploring and seeking tax efficient ways to sell the Timber. I think the answer is, we seem to have discovered a way to sell at least part of the Timber in a reasonably efficient manner. There's no way to escape the tax forever, but we may be able to defer some of it on some of the Timber. Jim?

Jay, the production looks pretty strong. We went ahead and moved it down, because we have seen the impact of the hurricane on offshore. So we felt that it would be appropriate to move it downward. But we feel that we will end up in that range. There is some upside to that, if we do get these wells drilled in the Gulf earlier than we anticipate. We're out actively looking for rigs right now, and hope to move very quickly to drill these wells. So the key is going to be the timing on getting those on. We don't expect them to be on before the end of the year. But if we can drill some of these at offset platforms, where we can hook them off quickly, that would provide a buzz before the end of the year.

Okay, thank you.

The next question comes from Mr. David Maccarrone with Goldman Sachs. Mr. Maccarrone, you may ask your question.

Thank you. Jim, I was hoping you could talk a little bit about basically the E&P strategy going forward? As I look at your annual report you basically project flat capital expenditures 2003 through 2005. Your stated strategy has been to live within your cash flow and pay down debt. As you look forward over the next couple of years, how much of the cash generation you do you look to pay down debt? And what sort of production growth or production curve do you see for the company, given that level of capital expenditures? And given depreciation that's likely to exceed those capital expenditure figures?

Okay, those are all very good questions. Going forward the key emphasis is going to be on gas, both in the development and exploration side. Emphasis is going to be in the Appalachian area and in Canada, where we feel that we see some great opportunities for gas. I think over the next five years you will see a significant shift to those areas in drilling for gas plays. We feel very comfortable that we have a lot of opportunities to drill both in Appalachia and in Canada.

Looking at what's going to happen going forward. As we've said, we're moving out of the Gulf, and it's very difficult to replace those high rate wells with onshore production, as I indicated today. That was part of the reason why we've moved that window of production for 2003 downward. Over time, we will find these opportunities to drill some wells in the Gulf that will give us a buzz; that will allow us to develop our onshore production. But what we will see over time is a gradual decline to a bottom point probably somewhere around 70 Bcfe in the next two to three years. And then it will gradually increase from that point on, as we then bring on these continual wells that we're going to drill.

So the key is going to be an occasional offshore well. Bright spot, the bread and butter type stuff that we used during the 90s, to supplement the onshore program that we’re doing. Then eventually flatten out the curve and then move it upwards after that. But we will be eventually out of the Gulf over the next five years, and be strictly an onshore, primarily gas, Appalachia, Canada. Then hopefully be able to supplement that with an additional basin or two with new acquisitions or new opportunities as we go forward.

And in terms of drilling, at least two incremental wells, as it related to the Pure situation, is that consistent with your $15m offshore capital program in the Gulf? Or are you reallocating among the $82m? Or is the better cash flow perhaps from the E&P business going to allow you to do that?

Well right now we're still, as we said, we're not changing our capital budget. What we are doing is reallocating, moving some of those dollars from what we were drilling on the oil side, to the gas side. So right now we're still not anticipating an increase. We're seeing rig rates offshore still very reasonable. There are still a lot of rigs available, so we feel that we're not going to be paying exorbitant prices to get a rig, even though the commodity prices are very high. So we feel very good that the overall well costs will not be out of line, and that we can live within the current capital budget.

Now if we get a lot more opportunities - and we are reviewing all our blocks currently to see if there is any other bright spots that become very economic at $4 to $5 - we might go back to National Fuel and present a case that we'd like to spend a few more dollars offshore.

You've mentioned that you're reallocating from oil to the gas side. What about within the regions? Are you shifting money from Canada to fund incrementally more Gulf Coast, or from the West Coast to fund some of the Gulf?

Yes, that's exactly what we're looking at doing, you're correct.

Okay. Thank you.

Your next question comes from Mr. Philip Salles with Credit Suisse First Boston. Mr. Salles, you may ask your question.

Thank you. I just want to know what you're looking for in the guidance that you reaffirmed today, relative to a gas price? What price were you using?

Jim, I'll turn that one over to you.

Okay. We had priced that out in mid-December, so the Nymex has come up somewhat a little bit, but we think it will tail back down. We've seen very strong summer prices - I'm trying to look it up here very quickly, we'll try to get it. The November 27th strip price is what we used, and we can get that out to you.

No, I'll take that offline with Margaret, later. The comments early on in the call said that CAPEX was being maintained. I was wondering, given the lower production guidance, do we look at that as additional costs or higher costs, or just -- you know, why are we not changing the CAPEX for E&P with the lower guidance?

Well the CAPEX was going to be maintained. What, we are looking at doing is shifting those dollars from onshore, which give you a buzz fairly quickly - because most onshore wells you can get on within three months - to some offshore drilling. That takes a little bit longer to get on. We anticipate those wells will be on some time in October/November timeframe, and those would give you a very good buzz for 2004. So what we are doing is shifting dollars from onshore wells that will impact immediately in 2003, to wells that will impact more in 2004. So that was the other small impact there to shift that downwards.

Okay, thank you. Just lastly, from Phil, just some comments relative to International. There are two projects that you identified last year, one was in Italy, just kind of your thoughts there going forward was about $200m for each project. I just wonder what your thoughts are given the current environment, if the plans are still to go forward with those two projects?

Well the plan never was, and still is absolutely not for us to spend $200m on those projects. That's the total capital costs associated with those, but we are not going to spend $200m. We are continuing to evaluate those projects on a regular basis, and re-evaluate them. Whether or not we continue with them depends on the extent to which we're able to get third parties in there to do the financing.

Okay, thank you very much.

The next question comes from Mr. Doug Christopher with Crowell Weedon. Mr. Christopher, you may ask your question.

Hi, thank you very much. I had it on mute, sorry about that. Just regarding the overall trend in the major expense items, could you go over a little bit like what your expectations are there in your $1.60 to $1.70 range? Specifically, how you might expect them to fluctuate? Is this first quarter trend as a percentage change in the level of different expenses, is that a good model to use going forward? Also, what would you expect the trend in interest expense to be for the next few quarters?

Unfortunately one of the things you have to do it delve into the individual segments as you start to look at expenses. Things like purchase gas costs. We've got tractors in New York and Pennsylvania to cover that in utilities, where you saw substantial increase in purchase gas costs. Those have an impact on the profitability of the utility operations. Things like the O&M expenses are under very good control in the utility and the pipeline and sewerage business. Then you've got some peculiarities of accounting if you lower things like work-over expenditures in the exploration and production side, very significantly from one period to the next depending what we're doing with individual wells.

We may have a well where one zone is depleted, and then we've got to re-complete the well in another zone. That can happen a number of times, and that makes it very difficult to predict those costs on a quarterly basis. A year ago we had some significant work-over expenses in that arena.

Well if we were to, for example, just take the exploration and production segment in the quarter, and look at the overall level of profitability there improving to about $25m. Going forward, even though the revenues might be lower, would you expect the level of operating income before taxes, for example, to improve over the next few quarters?

If prices don't improve, no, I wouldn't particularly expect the income to improve. What we have done is given some very detailed information about what we expect our costs to be on a unit basis. O&M costs per unit, [DB&A] costs per unit, and so on. Those are relatively fixed, are relatively predictable. Take those and apply those against your pricing model to give a reasonable indication of what might happen.

Okay. And also just lastly on the international front. When we look at the trend there over the past couple of years, profitable the first couple of quarters, not profitable the last two. Does that trend continue?

Absolutely. Yes, it's basically a weather dependent business. The Steam Heating business is just about like the Gas Utility business, you make money in the winter and you don't make money in the summer.

Is there anything over there that might reduce the level of unprofitable levels in the third and fourth quarter?

No, I wouldn't think so.

Okay, thank you.

Doug, before you hang up there. When you look at the O&M quarter to quarter, it's down in our first fiscal quarter from last year by about $14m. $10m of that represents a kind of funny accounting that had to do with the Enron hedges that we had a year ago. We had $10m worth of bad debt that we wrote off that's recurring. So when you look at it at first blush it looks like we've done something fantastic here with reducing costs. While we have reduced our costs, $10m of that has been with this unusual accounting with the Enron derivatives and their bankruptcy.

So O&M should remain relatively flat within the next few quarters?

It will fluctuate by quarter, but I'll defer to what Phil said earlier.

Okay. Thank you.

The next question comes from Mr. Sven DelPozzo with John S. Herald. Mr. Delposo, you may ask your question.

Good morning. I'm wondering, do you have any information on the Empire State Pipeline's throughput and operating income contribution perhaps in 2002? And if you also have any guidance for any second half of the year, 2003 expectations?

I think general guidance on an annual basis -- the rate base of Empire is about $135m. On an annual basis you would assume approximately a 10.5% overall return on that rate base. About 80% of their revenues are at a monthly charge, so that it would fluctuate by month, and volumetrically on the other 20%. But essentially operating income before interest, after tax, would be about 10.5% on $135m on an annual basis. Then we're assuming that we're going to get a favorable order out of the Commission, and that February first we would take over operations of the pipeline. So it would be roughly eight twelfths of that annual amount.

Okay, thank you. In the timber segment I noticed things like unit margins went up significantly and production went up significantly too. So in the past I've heard some comments like, that producing a lot in the Timber segment could lead to conditions of over supply and possibly depress the Timber margin. So since it wasn't like that in this first fiscal quarter, I'm wondering what room there might be in the future to continue to increase production, and whether that might impact unit margins in the segment?

Timber is very susceptible to the weather, the opposite of the Utility business. We were fortunate in the first quarter to have some favorable harvesting conditions. The crews were able to get into the woods and work effectively. As the weather gets worse and the snow gets deeper and the weather gets colder, it's harder and harder to produce the volumes that we did in the first quarter.

With respect to the margins, a lot of that is a difference in the mix of species that were harvested. The cherry logs and the cherry lumber that we get from those logs are much higher value product than a lot of the other species - almost any other species - oak or maple or what have you, is a significantly lower value than the cherry. So it was a combination of factors that led to those higher volumes and higher margins. Good weather, from a timber perspective, and the change in the mix.

And the mix in the future will be less cherry in the mix? What do you foresee?

It's going to average out over time, is what that amounts to. To some extent you cut the trees as you come to them, and it depends on the particular area where you're cutting. I think on the whole we tend to average somewhere around 40% cherry, somewhat less than that - looking at all the properties.

Okay, thank you.

Once again, if you would like to ask a question, please press star, one. One moment please. The next question comes from Ms. Kathleen Bugatidge (ph) with WH Reeves (ph). Ms. Bugatidge you may ask your question.

Thank you. Good morning. I was wondering if you could talk a little bit about the Empire Pipeline, what you're looking for in capital expenditures during the year? What kind of efficiency improvements you think might be achievable? Finally, what kind of price differential you're seeing from between the Southwest gas supply and the Canadian supply that's coming in that can tie into Empire?

I don't think we're looking at any significant capital expenditures this year beyond the acquisition of the pipeline. As we get to looking at operating efficiencies, we're going to pursue that very diligently obviously, but we don't have a predictor projection at the moment that we're talking about.

Were you talking about price differentials between Canada and the Southwest?

I was just wondering if you were seeing any -- you know you're in a period of very high demand with some volatility in prices, and whether you're seeing any differentials in the gas you're getting from Canada versus Southwest?

I think I know what you're driving at, and no, I don't know the answer to that question. We've got long-term contracts for different gas suppliers, so yes, we do see differentials, but I don't think those differentials are a reflection of the fat markets in some sort of a basis differential. If you're getting the notion, are we going to have cheaper gas supplies sourced into the Empire pipeline, or out of the Empire pipeline versus the gas supplies that would come from the Gulf Coast, I can't really answer that one based on our experience. I don't know if anybody else here has got an idea about that? No. We're all passing on that one.

Okay, thank you.

The next question comes from Mr. Denato Estay (ph) with Royalist Research. Mr. Estay, you may ask your question.

Thank you. I was just curious if you felt that the time you've spent on looking at the Empire acquisition, from an environmental standpoint are there any concerns or risks or extra money that needs to be spent there? Have you found that the pipe's been maintained up to standard and the like, Phil?

Yes, we don't see any problems with that at all. It's a relatively new pipeline and they seem to have done a fine job. We don't see any concern there.

Great, thanks.

The next question comes from Mr. David Maccarrone with Goldman Sachs. Mr. Maccarrone you may ask your question.

Thank you. Phil, I was hoping you could discuss how you develop incentive compensation targets at the E&P Company? What is it that drives your evaluation of performance? Particularly as you look at it not so much on a quarter or year-to-year basis, but over the next few years, what are the key targets that you're looking for the E&P company to hit? Be as specific as you can?

The absolute overriding target is return on investment. We just want to make money on the money that we spend. We're very concerned about not driving people to spend money unwisely, simply to meet targets that are based on volumes or reserves or what have you. The object here is to make money, and to invest the shareholder dollar wisely. I've said before on other occasions that I view out job as kind of managing a portfolio here. And we have opportunities to invest in Pipeline or Utility or Timber or International or whatever, and opportunities to invest in E&P. We put the money where it will do the best job.

What would you view as the current return on investment, and what is your objective in that business in a normalized pricing environment?

A normalized pricing environment is a difficult one to say. But over time, in that business it depends on the extent on which you -- that just depends on the kind of reserves that you're doing at home. But what we're trying to do is have a return on investment that's greater than our return on the other segments of the business, adjusted for risk. Or, over time, taking the pricing environment as we have them, and that means we're going to be somewhere toward the 14% or 15% return on equity.

And how are you assuming that business is capitalized?

Well we make an assumption of 50/50, debt to equity.

Okay, thank you.

At this time, Mr. Ackerman, there are no further questions.

Phil Ackerman. Well thanks, Christine. Thank you very much. Thank you all for participating. Margaret has got an announcement she's anxious to make.

I just want to indicate what the reply number is. We have issued a correcting number. We apologize for the error on the release this morning. The correct telephone replay number is 1-800-945-1660. With that, it concludes our call for today. Thank you all, goodbye.