National Fuel Gas Co (NFG) 2004 Q4 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the National Fuel Gas Company quarter 4 2004 earnings conference call. My name is Rachel and I will 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 today's conditions. If you wish to ask a question at that tame, key star followed by 1 on your touch-tone telephone. If at any time during the call you do require assistance, please press star followed by 0 and a coordinator will be happy to assist you. As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's, Miss Margaret Suto, Director of Investor Relations. Please proceed, ma'am.

Thank you, Rachel. Good morning, everyone. Thank you for joining us on today's teleconference call for a discussion of last evening's earnings release. Today's presenters are Phil Ackerman, Chairman, President and Chief Executive Officer of National Fuel Gas Company; Ron Tanski, Treasurer 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 fath, and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they're made, and you may refer to National Fuel Gas Company form 10-K on pages 60 and 61 of the 2003 annual report for a listing of certain specific risk factors. With that, we will begin the discussion with Ron Tanski.

Thank you, Margaret. Good morning, everyone. We announced consolidated earnings last evening for the fourth quarter of our fiscal year of $7.8 million or 9 cents per diluted share. As can you see from our earnings release, there were no nonrecurring items this quarter, unlike the fourth quarter of last year. For the entire fiscal year, consolidated earnings were $166.6 million, or $2.01 per diluted share. On a recurring basis, the consolidated earnings for the fiscal year were $164 million, or $1.98 per diluted share. Pages 7 and 8 of the earnings release detail the reconciliation between reported GAAP earnings and recurring earnings on both dollar and earnings-per-share basis. The details regarding the quarter and fiscal year comparisons to prior periods are in the earnings release, so I won't spend time repeating it all again here. For the quarter, the 9 cents per share of earnings was within our expected range, and there were no major deviations from our forecast that we would need to note here. In our Pipeline and Storage segment, deficiency gas revenues for supply corporation, net of hedging, were $4.251 million for the quarter in connection with volumes of 558,364 MCF.

We're busy in the Utility segment with rate case filings in both states. In New York, on August 27, we submitted a base rate filing for rates to become effective August 1, 2005. Our filings include the following basics: New York rate base of $686.144 million, and we're seeking a 9.1 percent return on that rate base, and we have projected the following capital structure at the following cost rate: Common equity, 51.09 percent of the cap structure with a return on equity of 11.875 percent. Long-term debt, 38.71 percent of the GAAP structure at 6.58 percent. Short-term debt, 9.4 percent of the GAAP structure at 4.939 percent and finally, customer deposits, 0.8 percent at a rate of 2.45 percent. Now, that filing was calculated to increase rates by a net $41.2 million. In Pennsylvania, on September 15, we filed for a base rate increase to become effective June 16, 2005. The Pennsylvania filing includes the following basics: Pennsylvania rate base of $279.252 million, and we're seeking a return on that rate base of 9.16 percent with the following projected cap structure and cost rates: Common equity, 51.5 percent with an 11.875 percent return on equity. Long-term debt, 42.49 percent of the cap structure at 6.65 percent. Short-term debt, 6.01 percent at a rate of 3.48 percent. The Pennsylvania filing was calculated to increase rates by $22.78 million. Now, we're still early in the process with an 11-month suspension period in New York and a 9-month suspension period in Pennsylvania. Commission staff in each state won't file their case until late December. And because new rates won't take affect until next summer, we won't see any meaningful contribution to earnings from the rate cases in fiscal 2005, but we'll keep you posted as the cases progress.

During our last call, I had mentioned that our New York utility had also made a filing to remove a bill credit that has been in place since October 2003, the effective date of our last New York rate settlement. With the credit removed, we had the potential of increasing revenues by $5 million over the course of our 2005 fiscal year. Many of you may have already seen the order on the Public Service Commission's website that denied our request. We think the order is based on some calculation errors in their analysis, and we're attempting to get that straightened out in a rehearing. Regarding consolidated performance for fiscal 2005, we have kept our earnings guidance in the range of $1.75 to $1.85 per share. Unless we get either of the rate cases resolved early, the cost pressures that we're facing in the utility are expected to reduce earnings in that segment compared to fiscal 2004. And also, because of some area pricing differences that Jim Beck will talk about, our California heavy crude production is not getting the full benefit of the current higher oil prices. As a result of those issues, we're keeping with our previously-announced 2005 earnings guidance.

Looking at the first quarter of fiscal 2005, we expect earnings to be in the range of 54 to 60 cents per share. Just a final word before I turn it over to Jim, with our renewal last month, we have a $220 million committed credit facility in place through late September 2005. There are no outstanding borrowings under that facility. And under our commercial paper program and bilateral lines of credit totaling $600 million, as of yesterday, we have borrowed only $191.6 million under those facilities. We also have the universal shelf registration on file, under which we could issue an additional $550 million of either debt or equity security. We're hovering close to our target of 50 percent debt to total cap structure. We have ample liquidity and our cash flow during 2005 will more than cover our entire planned capital expenditure program for the fiscal year. Now, I will turn it over to Jim Beck.

Thank you, Ron, good morning, everyone. Seneca's earnings for the quarter are a result of all the hard work of our staff to take advantage of these high commodity prices. While earnings for the quarter were up 46 percent to 10.3 million, excluding last year's impairment, production for the quarter was down 21 percent primarily due to last year's sale of our southeast Saskatchewan properties. In our East division, production was down less than 3 percent, primarily due to weather delays on new well drilling and completions. In the West division, production was down 7.3 percent primarily due to declines in our older Midway Sunset wells, and we're currently working to remedy this problem. The good news came from the Gulf, where we were able to keep production nearly flat to fiscal 2003 levels. In Canada, production was down nearly 64 percent from last year's quarter due to the sale of our southeast Saskatchewan properties. Excluding the property sale, Canadian production for the quarter was down 5.1 percent. New wells drilled in 2004 and waiting on pipelines, plus wells to be drilled in fiscal 2005 in both Alberta and British Columbia, should help reverse this trend this in Canada.

As forecasted, Seneca's total production for 2004 was down 19 percent to 60.2 BCFE, compared to 74.2 BCFE for 2003. Among other notable items this quarter was a reduction in our operating expense. Excluding related costs to our southeast Saskatchewan properties that were sold, Seneca's lease operating expenses were down 6 percent. This is a result of all of our divisions working to become more efficient. Seneca's total capital expenditure for fiscal 2004 was only 77.7 million, versus or forecast of 92.4 million. The main reason for this shortfall was the lack of spending in the offshore, where we saw only limited success in our farm-out program, which, in turn, meant Seneca didn't have to spend any capital. And in Canada, we only participated in one Sukunka well. There were also limited exploration opportunities and weather delays in our northern divisions. These factors resulted in fewer wells being drilled during the year. Now, as I indicated last quarter, Seneca has been looking for a high quality prospects in the gulf. We were pleased to announce yesterday that we have closed a deal with Chanex, whereby Seneca will acquire a 45 percent working interest before project payoff and 6 offshore blocks that have 7 shallow, 3 deep control bright spot gas prospects. Seneca will operate these blocks and participate in drilling at least 3 wells to 4500 feet in early 2005. We are excited about these opportunities as they are the type of prospects Seneca successfully drilled in the '90s, only now, gas prices are over $7. In Canada, we are waiting on Talisman, the operator of our Sukunka properties to provide us with their future plans. As soon as the results from our third Sukunka well are released by the operator, we will release that information.

Looking ahead to fiscal 2005, our forecast has not changed since the last quarter. Seneca anticipates spending all of its 2005 capital budget of 88 to 93 million. We have 6 offshore prospects ready to drill and are currently waiting on a rig. In addition, Seneca's implemented its onshore exploration and development plans. We have rigs drilling in our East Canadian and West divisions, and plan to drill over 150 wells in 2005. Looking forward to our expectations for the first quarter of 2005, production should be between 12 and 14 BCFE, and we are reiterating our target for 2005 production of 50 to 55 BCFE. New production from our early 2005 drilling in the gulf, plus production from West Cameron 77 mentioned in the press release, should provide a solid base to achieve this goal.

Commodity pricing used in our guidance is the NIMEX-based, based on prices as of July 22nd. The basis adjusted average prices without hedges for 2005 are gas at $6.21 per MCF, and oil at $35.16 per barrel. This compares to our 2004 actual unhedged basis adjusted prices of gas at $5.51 per MCF, and oil at $32.98 per barrel. There is one note of caution about 2005 commodity prices. With the recent run-up in oil prices, we have seen an increase in the basis differential in California. As prices peaked over $50 per barrel, the basis increased to over $12 a barrel for California heavy crude. This is up from approximately 550 per barrel. If prices remain high, this may limit some of our projected revenue increase. This differential should come down by the end of our second quarter fiscal 2005, the impact of this basis differential change on earnings will be reviewed shortly. Our expenses on an MCF -- dollars-per-MCF basis as follows: DD&A is now expected to be in the upper portion of the range of $1.50 to $1.60 per MCFE. LOE, including taxed but excluding plant expenses, will be in the range of 91 cents to $1.03 per MCFE and G&A will be in the range of 24 to $27 million.

Hedging for fiscal 2005 can be summarized as follows: As of October 28, we have 16.7 BCF of gas production hedged in the average price of $6.22 per MCF. And 2.85 million barrels of oil production hedged at an average price of $30.44 per barrel. Based on the average prices we just provided, the earnings sensitivity to price changes for 2005, assuming a static basis, is as follows: For each 25 cent change in the average gas price for the year, earnings will change by 3 cents a share. For each $1 change in the average oil price for the year, earnings will change by 1 cent per share. However, as we have indicated, we saw have seen a basis increase in California. For the first quarter, a better estimate of the oil price impact on earnings would be 0.3 of 1 cent for every $1 change in oil price. We expect the earnings sensitivity to return to normal once the heating oil crisis has ended. For fiscal 2005, we remain focused on living within cash flow and continuing to expand our activity mainly through drilling. At this point, I will turn it back to Phil.

Thank you, Jim. Well, 2003 was a very eventful year for us with a number of significant transactions, 2004 was more quietly productive. We paid down over $200 million in debt. We worked hard and are working hard on the Empire Millenium Connector project. We reluctantly but necessarily filed rate cases in both New York and Pennsylvania. There was good news that we worked hard for, such as settling the Fordham matter with the New York Public Service Commission, and extracting additional value from the sale of our southeast Saskatchewan properties. Then there was good news that just happened. Like the change in the check tax rate that gave a nice boost to the earnings on a nonrecurring basis from our International segment.

Those of you that have been following the Company for a long time have heard us speak many times of our diversification goal as being approximately 1/3 in Utility, 1/3 in Pipeline and Storage, and 1/3 in Exploration and Production. Well, this past year of 2004, the Utility earnings per share were 59 cents, Pipeline and Storage was 60 cents, and Exploration and Production was 61 cents. Now, while those total only $1.80 of our $1.98 of earnings excluding nonrecurring items. There were, obviously, other segments contributions that total 18 cents to make up the difference. Plus, each of the principle segments that contributed approximately 30 percent of our earnings as opposed to a full third, but still, I'm happy to have those contributions from the smaller segments.

Now, the critical thing is to look at the proportion of net plant, which each of those segments represent, and there are a number of obvious implications that come from that analysis. First, we needed to file utility rate cases and we have done so. Secondly, it makes sense to find more Pipeline and Storage opportunity. And we are working hard on that Empire-Millenium Connector project and anticipate when that's completed, it in turn will lead to additional storage opportunities. Finally, Exploration and Production is holding its own with 30 percent of the earnings and 30 percent of the investment in net plant. The challenge in earnings -- Exploration and Production, however, is to grow that segment. At the same time, achieving appropriate returns. We see that this is a challenge for many companies. Today's Gas Daily, for instance, lead story is the fact that Shell, Unocal and Exxon-Mobile all had declined in their quarterly gas volumes. Short-term with respect to Exploration and Production, are hedge prices for '05 are higher than those that we locked in for '04, and in turn, the hedge prices for '06 are higher than those that we have for '05. So we should have a growth in the realized prices for our production. Increasing the volumes remains the challenge. But we have high hopes for the Chanex deal, which Jim just discussed.

The returns in other areas vary widely, with marketing having earnings of over $5 million and next-to-nothing in terms of a net plant investment. International had earnings of only $1.2 million, excluding the nonrecurring items, but I would point out those were positive earnings. On the other hand, the currency translations gain that -- were substantial in the International segment are varied in other comprehensive income and the tax rate change resulted in a nonrecurring gain. Speaking of the check assets and international, the American Jobs Creation Act of 2004 appears to have favorable language with the respect to the repatriation of foreign earnings, which could positively affect our International activities with respect to either fiscal '05 or fiscal '06. This is just one way in which fiscal '05 is off to a good start. Others include the Chanex deal, having bad debts under control, see the pension's funded status improving. These and a myriad of similar details make me look forward to 2005 with confidence and anticipation. I think we're off to a very solid start to a very good performance in 2005. With that, operator, I would like to open the call to questions.

[Operator Instructions]. Jay Yannello, UBS.

Good morning. I'm just wondering -- your reaffirm guidance of $1.75 to $1.85. What is the price assumption for the unhedged portion of production?

That pricing was in Jim's remarks, Jay. Let me just take a look back here, unless, Jim, you have that ready at your fingertips.

Yeah, that is based on the NIMEX pricing from July 22nd, and those basis suggested prices that we were using going forward were the 621 for gas for the whole year and the 35.16 for oil.

Okay, sorry. I took a call then. Second question is as far as the international development projects, I guess there was, there's a few pending still. Is there any update on them?

Well, first, I don't characterize it as a few pending. Just only two, we continue to look at Italy and Bulgaria and, you know, there's still limited progress being made with respect to either one of those. I wouldn't say that the situation has changed from the last quarter or the quarter before that.

Okay. Thank you.

Devin Goghegan, Zimmer Lucas Partners.

Hi, this is Devin Goghegan. Nice attempt. I just wanted to get a better feeling for the cost increases in the LOEs. I know some of it's due to production taxes, which are beyond your control, and that's fine. What kind of cost increases are you seeing that is in your control and what can you guys do to try to slow down a little bit?

Okay, I assume you're referencing the LOE for EMP?

Yes, sir.

Okay. We're seeing about a 7 to 10 percent increase in LOE from the service companies, and they're talking about potentially another increase if rig activity stays strong sometime next year. So, we're working there to -- to keep those costs down by going out and doing a lot of bidding. The other thing that is impacting our LOE. We were very pleased that we could lower it by 6 percent considering we're shifting away from the offshore, which is historically, a very low-cost operation area for LOE and moving into higher-cost areas in the onshore. And so we were able to reduce our LOE costs even though we're making that transition. One of the key things that we're going to be looking at for next year is reducing the costs in California. As you know, we do a lot of steaming and we have to buy gas to do that, and with gas as high as it is, it's very expensive, and we have implemented a project now where we hope to -- we're going to start using our, what we call casing vapor recovery gas, and that will significantly reduce our operating expenses in California. And we hope to talk more about that at the New York conference, which -- and webcast, which will be coming up in a little over two weeks.

Great. Thank you very much.

Mike Heim, A.G. Edwards.

Thanks. I appreciate your comments about Gulf of Mexico production being flat versus last year, but I couldn't help noticing that gas production in specific went from 4.6 BCF in the June quarter down to 3.5 BCF, or down 22 percent. Could you talk a little about the timing issues, the wells coming on, or hurricane damage, or anything that would explain why those are bad quarters to compare?

Okay. We did have a little bit -- we had about 4 days --3 or 4 days of down time in the Gulf, which impacted some of the wells, but not all of the wells. One of the big changes that we have -- occurred in the Gulf was on our 345 block, which was a very strong, it's 100 percent gas producer. We owned it 100 percent, and that well started cutting water. And with the MMS now, they don't allow you to come up and do recompletes until it reaches the very ultimate economic limit and, this well is just now getting to that point. It was making over 10 million a day. It's now down to 600,000 a day and producing 1800 barrels a day of water, and we have to get approval from the MMS before we can do a recomplete to another zone that we have in the well, and they just don't let you do it until they think it's uneconomic. So, we have been limited on being able to do this recomplete. We have a zone up, up hole behind pipe that tested over 10 million a day, and we were not able to make that recomplete until the MMS says it's okay. So we now have a permit files with the MMS and we're waiting for their approval. So that is a significant shift in total production. But you can expect in the offshore, we do see decline rates of 30 percent and higher, and that is very normal for the offshore. We do have the west cam 7796 block, which will be coming on sometime after January. We're waiting on the operator, Newfield, to let us know when. That will help us and then some of our drilling for 2005 is going to be off of platforms and those are very easy to hook up and put on and we're trying to drill those wells first in the early part of the year. That's the first well we're going to drill offshore, it is going to be off one of our platforms, where we could get those wells on very quickly. But in general, can you expect declines in gas production offshore to be on the 30 percent range going forward and then it's just a key is, drilling new wells to replace that production.

30 percent year-over-year.

Correct.

Okay. Thanks. That's helpful.

Philip Salles, Credit Suisse First Boston.

Thank you very much. Wondering if you could just review the hedging strategy. It seems that the hedges that are in place currently are very similar to the July timeframe, and with the rise in commodity prices, I wonder what the thoughts are. It appears that about 40 percent of the production is unhedged. So, any specifics that you can give to hedging and, and volumes going forward would be helpful.

Well, we continue to follow what we think is the same strategy that we have had for several years, which is to have approximately 2/3 to 3/4 of the production hedged as we go in to a fiscal year, and, you know, we're starting to build hedge positions out into 2007 now. At the same time, we're not going to hedge volumes, which are merely projected and are not in hand. I'm not going to take a naked hedge position, if you will, on the expectation that certain wells are going to be successful, so there is some limitation with respect to the strict 2/3 or 3/4 of our expectations, if, in fact, those expectations aren't represented by things that we can see, feel, and touch.

All right, I guess I was just looking at the guidance that Jim gave on the call and what is actually disclosed in the press release. It still seems that you have some room for additional hedges and given the run-up in prices when gas crossed $9 the other day, I just thought that we meet see some higher volumes being hedged.

We continue to add additional layers on a regular basis.

Okay. That's fair. Jim, could you, could you review some of the, you know, the production in -- in the fourth quarter in Canada. It seemed to decline sequentially and share with us what was going on above the border up north and, and the reasons for the declines.

Okay. One of the -- that's a good question. The -- one of the key things that happened in Canada is getting wells hooked up up there. We have roughly between 8 and 12 million cubic feet a day of gas that is waiting on pipelines. And that is one of the big problems we're having is getting these hooked up. There is a limitation on there on processing and so you have to be very careful in who you hook your wells up to, and what pipelines you hook up to so that you can get your rates, the one you want. They don't let you just build a processing plant like they do in the U.S. where if you have a well, you want to build plant to process that gas, you can't do that up in Canada, so that does create some road blocks in hooking wells up. So we have been diligently working to identify the pipelines where we can produce our wells at capacity without running into limitations on processing. And so that's where we have a significant amount of gas now, bottlenecked, waiting on pipelines. And as soon as we get those hooked up, they're working as fast as they can to get all the permits approved and get it on and we expect a lot of that gas will be coming on either this quarter or early next quarter. And that should significantly improve the situation in Canada. And then we're continuing to drill there. It takes about a month to drill a well -- or I should say, two weeks to drill it and about a month to get it hooked up if you don't run into any problems, and so we're actively drilling there now and hopefully we'll get these wells hooked up as soon as possible. But that's -- the -- there are a lot of regulations you have to follow in Canada and that does create some limitations on getting wells hooked up as fast as we would like.

Thank you. Similarly in Appalachia, if I recall from last quarter, you talked about weather and delays and actually, I think you even actually said that it was muddy or something along those lines. It seems, again, in the fourth quarter, you, you pointed to weathers as limiting production coming on. Is this something that is going to be -- you cannot control weather, but is there something that we could do or look at that could actually aleve some of that pressure that's coming from weather and see an improvement in volumes out of Appalachia next year?

You have a good memory and you're right. Weather has been a persistent problem there, it's been very wet. Most of our drilling is back up in the forested areas. Not only do you have to more or less have dirt roads back into this area, we're very conscious of pollution. We don't want to get runoff causing us a problem, so we're limited on what we can do, how much earth disturbance we can have. We have to continually monitor the amount of acreage that we have disturbed and if -- if there is, we have to reclaim part of our land before we can build new roads and with the muddy conditions that's limited to how much we can get reclaimed, all of these things sort of compound and create or delay the drilling activity and the completion activity in Pennsylvania. There's not a lot we can do. Down here in Texas, we build board roads. We do that in Texas and Louisiana if you're getting into muddy situations or just put caliche down, but we're limited as to what we can do there, so we try to live within the rules and regulations of Pennsylvania and, again, we're working as diligently as possible to drill the wells and complete them as fast as possible, but there are some things that just delay us and, over which we don't have any control.

Well, along -- similarly, you know, taking it region by region, in, in the west coast, you talked about steaming, the high cost of gas kind of impacting the margin there. But a new technology that might improve it. Having said all of that, it seems that there are hurdles in each of the regions we have seen that this year. What gives you the confidence, or the comfort that you're going to reach next year's production levels?

We feel very good; you know, we talked region-by-region if you take a look at the west coast, you know, this new scrubber technology that is going to allow us to use CBR gas will significantly reduce the steaming costs and we will talk about that more here in the next, in our presentation in -- and webcast in New York. The production that we have seen in California we're finding all the operators are experiencing the same problems, and what we have done is we have done some test pulls on some of our production liners in there and found that they're plugged. Probably due to the fact a year, I guess it was over a year, a year and a half ago when we stopped steaming, some very tar-like material precipitated out on the casing and plugged them. So we think now that we're going to be pulling those old liners and replacing them and so far, where we have done this, we've seen a significant improvement in production. So we think we have identified that problem and we'll be able to fix it. Plus, we have just kicked off a new 52-well drilling program in the Midway Sunset area to add new production there. So, we feel very comfortable that California's in good shape. In the Gulf Coast, we do have our seven-well program. We should have our first rig on location mid-November. We have our 3 wells from the Chanex deal, which will be kicked off right after the first of the year, plus, we have a number of other quality prospects that we're ready to drill and it's just a matter of getting the rig. Gulf coast, whole we're still looking at typical declines on the older wells of 30 percent, by concentrating our drilling on wells that can be put on very quickly from old platforms, we think we can offset a portion of that decline. Canada, we're continuing to be successful up there. We're still having a good success rate. We are adding new production and really it's just a matter of getting those wells hooked up. As I said, we've got between 8 and 12 million cubic feet a day of gas just waiting to be hooked up,and as soon as we can get that done, we think that will improve our Canadian, and then our ongoing drilling in Appalachia, we have got over 50 wells planned there. We have got rig running right now. We're completing those wells and hooking them on as quickly as possible, as long as the weather allows us to continue to do that, but overall, we feel very good that that 50 to 55 is achievable for this year.

Thank you, Jim. Jim, being that you feel so good, would you like to share with us your reserves for fiscal year end?

Let's see, I -- yeah, we've got that number. Let me dig it up here and I'll get it for you in just a second.

Okay. Thank you very much, appreciate it. Thanks.

I would just like to jump in here and re-emphasize as I have a couple of times before this year that I think people understand that I want us to make those reserve numbers -- or those production numbers that I'm tired of the years that we didn't make the numbers that we forecasted in terms of production. We've had a number of conversations sayings about each of the areas and what it's going to take to make the forecast of production that we have put out there. And I believe that people know what it is that we need to do in order to make those numbers and I expect to -- fully expect to see those numbers met. The other thing to go back to, the first question you that had, Phil, about the -- the level of hedging, my calculation is that we have got about 68 percent of the 50 BCF level of forecasted production hedged. You know, which is something over 2/3. Now, whether we might get another bump up along the way is a possibility. But we're certainly, by my calculations, in the range of the hedging policy that we have in place.

Thanks, Phil. Thank you.

Okay, I've got that reserve number. Year-end reserves, 930.04. BCFE level be about will be about 616063. That's 616 million, 063. That will be the year-end reserve numbers for 2004.

So, if -- if I recall that's -- that's a little bit -- that's modestly down from the prior year, Jim?

That's correct.

All right. I think last year you had what, 670 about?

That's correct.

Okay.

You have got a great memory. [ Laughter ]

Yeah for my old age, it's not so bad. I appreciate all the help and the insights. Thank you very much.

David Maccarrone, Goldman Sachs.

Hi. Look at your EMP CapEx, it looks like you underspent by a descent margin again, and I was wondering, how should we view this, you know, looking at, you know, your commitment to improved financial discipline going forward, versus the appeal of the internal drilling opportunities that you have and, you know, maybe later into that, how does this strong current cash flow, as well as your ability to hedge at relatively high prices, impact your views toward your current CapEx budget for '05.

I guess that's a pretty complicated question. Yes, I think we have imposed a higher degree of accountability or financial discipline perhaps than we have in the past. I think that the -- we've said before that this is a living budget, the fact that we didn't spend as much in '04 as we had projected as some kind of an indication that we don't feel compelled to spend money when we don't think we have the opportunities that warrant spending the money. Conversely, if we find opportunities to spend money that we think are suitable, we'll spend more than the budget. We have the cash flow to do that. To some degree, some of the limitations and investment opportunities are physical ones. Jim spoke quite a bit there about the constraints in Pennsylvania, for instance, with respect to earth disturbance and so on. I would be happy to drill more wells in Appalachia, and we're working toward that end in terms of getting more personnel to identify prospects and to increase our capability of drilling there. But there are constraints on that. So, too, in California, we're bumping up against some constrains there in terms of physical abilities to squeeze wells in -- squeeze wells in to the existing Midway Sunset properties. At these oil prices, it's very attractive to accelerate that production, and we're trying to do that. You were -- we're trying to spend as much money as we prudently can. We certainly have the financial resources available to us. But like a great many producers, we're finding ourselves to be more prospects constrained or constrained by regulatory issues.

To that extent, I mean, if you look at your '04 numbers, take DD&A and net income out of EMP and subtract CapEx, you got over $50 million, 65 cents per share of excess cash flow, you're now at a debt-to-cap debt is ahead of your target and seemingly only getting better. Beyond Empire, if you have this sort of EMP budget, and maybe you achieve it or come up a little sort, where do you anticipate putting that cash flow? Do you feel comfortable increasing the rate of dividend growth or -- or buybacks, or do you just want to, you know, sort of save for a rainy day?

Oh, I think we would save a little bit for a rainy day, but is doesn't make sense to build up -- to me, to build up some huge cash position. Nor would I be comfortable substantially increasing the rate of dividend growth. I think the preferred alternative would be a stock buyback.

Okay. Thank you.

Sven Del Pozzo, John S. Herold.

Hi, yeah. Most of my questions have been answered, but one curiosity, I don't understand why lumber sales volumes appear to be pretty strong in comparison with last year, even though almost half of your acreage was sold.

That's a reflection of -- the lumber is a reflection of the output of the sawmills. And to some extent, we have been buying logs to mill. The real profitability in that whole Timber operation has to do with the sale of cherry veneer logs, which we did not mill but sell as whole log, and you will see that the overall profitability of the Timber operation has declined about half commensurate with the fact that we sold about half of the Timber properties. We did accelerate some of the cutting this year in particular because of some wind damage that occurred where we hurried up and got in and salvaged the trees that had been blown over. So that tipped the scales a little bit, so it was not quite exactly half. The lumber sales itself, while profitable are not the high-margin items that really drive the profitability of that segment. It's the cherry veneer logs. And it pays to run the mills, and to the extent that we need to buy logs from third parties in order to keep the mills going. We will do that. That's what we did.

All right. And a last question for Jim, is there any news on, when a next appraisal well might be drilled in the Sukunka area with Talisman?

The -- we are waiting on Talisman, as operator, they control the flow of information about the Sukunka area. So we're at their mercy on releasing information. We're working with them to try to get as much information out as soon as possible, and as soon as they release it, we will get it out to you.

All right. Thank you.

Jay Yannello, UBS.

Thank you, just a quick one. As far as the $5 million credit, I guess you're saying there might have been a discrepancy. There might have been some numerical issues with it. Can you give us a sense is there a timing when we might have ultimately have resolution on why this?

Jay, no. We can't give you anything definite. We filed our petition for rehearing and it just has to works it way through the commission process.

Okay. Thank you.

Josh Silverstein [ph].

I was just wondering on the EMP production, that 50 to 55 BCFE, did that include the potential from the West Cameron well?

From the 77? Yes. That's in -- in those numbers. That's correct.

Okay, but previously that was not in the numbers?

Well, we would provide a range, you know, and that's why we have the range and we still feel we're comfortable in that range.

Okay. And then can you just run over the working interest that you guys have there? I thought you were able to back into 25 percent, but I guess you said 11.25 there?

Right, that's 25 percent of the Newfield interest, and they had a 45 percent interest, so we get 25 percent of their 45 percent so that's how it got to the 11.25.

Okay. And they put out in their conference call that they saw a -- sorry, a predrill reserve amount of 60 BCFE. Is that what you guys heard from them as well? This was in their call that they put out two days ago.

Okay. Typically companies do not share reserve information. I didn't know that that's what they had on it. Each company does their own, and we tend to be a lot more conservative. So we, you know, I -- I trust them to do their work, and we do ours, and if that's what they think, then that's a good starting point for us to work from, but we don't use other companies' reserve information when we do our reserves.

Okay, and they had also mentioned that they think production is going to come online in mid-April, and I guess you guys said earlier on the call that you think it might come on, I guess in January?

It was after the first of the year. We didn't, you know, you probably got more information. We're still waiting on AFEs and information from them. We have not had a partner meeting with them, so we don't know for sure what -- what the timing would be. We would know once we had a partnership meeting.

All right. Thank you.

If they said April, then that's probably a good date.

Got you.

Thank you, sir. Ladies and gentlemen as a final reminder, to ask your question at this time, please key star 1. And at this time, there are no further questions. I would like to turn the presentation back to Miss Margaret Suto for any closing remarks.

Thank you, Rachel. We would like to thank everyone again 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, November 5. Our website address is www.nationalfuelgas.com. The telephone replay number is 1-888-286-8010 using pass code 35213587. This concludes our call for today. Thank you, and goodbye.

Ladies and gentlemen, thank you for your participation on today's call. This does conclude your presentation and you may now disconnect. Have a wonderful day.