National Fuel Gas Co (NFG) 2004 Q2 法說會逐字稿

Good day, ladies and gentlemen, welcome to the Q2 2004 National Fuel Gas Company 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 toward the end of today's conference. If at any time during the call you require assistance, please press star followed by 0 and a coordinator will be happy to assist you. I would now like to tush the presentation over to your host for today's call, Miss Margaret Suedo, Director of Investor Relations. Please proceed, ma'em.

Thank you, Rachel. Good morning, everyone. Thank you for joining us today for the teleconference call for a discussion of last evening's earnings release. Today's presenters are Philip Ackerman, Chairman, President and Chief Executive Officer of National Fuel Gas, Ronald Tanski, Treasurer of National Fuel Gas, and James Beck, President of Seneca Resources Corporation. 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.

Our national fields 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're made and you may refer to National Fuel Gas 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 call with Ron Tanski.

Thank you, Margaret. Good morning, everyone. This is the first teleconference since National Fuel started hosting them in the early '90s but we won't have a pleasure of hearing Joe Filowski (ph) discuss our quarterly earnings. As many of you know Joe retired on April 1, after 28 years with National Fuel. I spoke with him last week and he's already in full retirement mode. Getting his boat ready for the upcoming sailing season on the Great Lakes. I would like to thank Joe for all of his help during the years and especially for leaving us a solid quarter to talk about. As we announced last evening, consolidated earnings for the second quarter of our fiscal year on a diluted, per share basis were 93 cents per share compared to 99 cents per share for the same quarter last year. Excluding non-recurring items, earnings for the quarter were 95 cents per share.

Pages 8 and 9 of the earnings release detail a reconciliation between the reported GAAP earnings and recurring earnings on both the dollar and earnings-per-share basis. The earnings release provides quite a bit of detail comparing the current quarter to last year's quarter so we won't spend time repeating it all again here. While earnings were down year-over-year, there were no major surprises. Higher commodity price was the primary driver for the difference between the high-end of our 85 cents per share earnings guidance for the quarter and the 95 cents of recurring averages per share that we achieved. Now, as I said, the release provides all the details of the year-over-year comparison so I'll just talk about the items that caused us to beat our guidance by 10 cents a share. As shown on page 14 of the earnings release, the weather this quarter was approximately 3% colder than normal but still over 4% warmer than last year.

Even though colder-than-normal, the high pricing environment continued to cause customers in the utility segment to cut back somewhat on consumption. On the other hand, that same high pricing allowed efficiency gas and the pipeline and storage segment to be higher than forecast. So on a combined basis, the regulated segments performed inline with our expectations. The 10 cents of earnings above forecast came primarily from the company's non-regulated segments. The exploration of production segment exceeded their forecast by approximately 6 cents per share, higher than forecast production in the Gulf Coast, primarily in the High Island area, and prices that remained consistently above forecast for the main drivers. The international segment exceeded forecasts by approximately 2 cents per share due to slightly higher margins and the appreciating value of the Czech currency. The marketing segment was ahead of forecast by a little more than a penny because margins stayed stronger than were forecast. And the final penny is made up in corporate and other rounding across the system. In terms of future guidance, the earnings release provides guidance of 20 cents to 30 cents per share for the June quarter.

That leaves approximately 7 cents of earnings for the last quarter or said another way, we're providing earnings guidance of 27 cents to 37 cents per share for the next six months. Well, that's a pretty wide range. Volatility and commodity pricing and the risk of production cutbacks in the Gulf during the hurricane season caused us to be that conservative. We have continued to improve our balance sheet. We paid down long- and short-term debt and our equity component was up to over 47% at the end of March. On track with our forecast to achieve 50% next year. Two additional items we're continuing to focus on, are the impact of high commodity prices on our customers and FERC order 2004-A.

Our consolidated accounts receivable balance is down by $38 million compared to last year and included in that decrease was a $12 million year-over-year reduction in accounts receivable in the utilities segment. However, we have seen the aging of those accounts increase slightly since last year indicating that some of our residential customers are having a little difficulty paying their bills. During the summer, we hope to convince more customers to move to our balance billing program and to assure that all of those that are eligible make arrangements to apply for heating-assistance programs. The recently issued FERC order 2004-A has us busy trying to figure out ways that we can continue to make offsystem sales. While not a big component of our own overall earnings, the sharing of 85%, the margin associated with those sales, with our ratepayers, helps mitigate their bills and makes us eager to continue those sales. We expect that we'll get further clarification on that order before it goes into effect on September 1 and that we will have a way to deal with that. With that, I'll turn it over to Jim Beck to discuss more details about the exploration and production segment.

Thank you, Ron, and good morning, everyone. Our emphasis during this quarter was the same as it was in the first quarter. To ensure we're producing at the highest reasonable rates possible and to increase our hedge positions for 2005-2006. A review of the financial results is summarized in detail on pages 13-16 of yesterday's press release. In addition to that summary, we'll provide you with a short overview of our current activities. Higher commodity prices helped the second quarter results, along with production for the quarter of 15.83 BCFE. This was an increase over our first quarter of 15.6 BCFE and keeps us on track to meet our 2004 forecast of 57 to 62 BCFE. However, it should be noted that Seneca's not expecting any new offshore production to come online in the next six months. Therefore, our production rate will start decreasing over the next two quarters.

Seneca's net income for the quarter increased to 14.nineteen million or 5% high -- 14.9 million or 5% higher than the second quarter in last year, this is despite a 19% decrease in production from our 2003 results. Seneca's net income for the quarter increased to $14.9 million or 5% higher than the second quarter of last year, this is despite a 19% decrease in production from our 2003 results. The improvement in earnings was primarily due to higher realized prices for both oil and gas and lower operating expenses in Canada. A portion of the higher-realized prices was due to hedging. Seneca increased its hedge positions for both 2005 and 2006 by adding a number of significant new layers to its hedge program. A summary of those positions can be found in yesterday's press release. The current average hedge price per oil for 2005 is $28.68 while gas is $5.72. Seneca will continue to add hedges for fiscal 2005 and 2006 as target prices are reached. Drilling proceeds ahead as planned with 44 gross wells or 41 net wells drilled during the quarter with a 91% success rate. Our capital 2004 budget remains unchanged at $90 million. However, that does assume development activity in the offshore.

Looking ahead to our expectations for the third fiscal quarter, we anticipate production between 14 and 16 BCFE since it's spring breakup, drilling is expected to be down to approximately 30 wells in the third quarter. And lastly, with the current high commodity prices and increased hedging, what is the impact of price changes on Seneca's 2004 earnings for the next six months? Currently for each $1 change in the average oil price for the remainder of fiscal 2004, earnings will change 1 cent per share. While for each 25-cent change in average gas price for the rest of the fiscal year, earnings will change about 2 1/2 cents per share. This is based on our budget pricing, which is an average basis adjusted price for the remainder of fiscal 2004 of $22.37 per barrel of oil and $4.89 per MCF of gas. We have not done the sensitivities yet for fiscal 2005 since that budget has not been completed and won't be completed until July of this year. So with that, I'll turn it over to Phil.

Thank you, Jim. We have done a lot in the last couple of years. And at this point, I have any number of reasons to be pleased with the results. Obviously our quarterly earnings are ahead of consensus and ahead of our guidance. What has been a sore subject, namely oil and gas production lines, continues at a comfortable pace to meet our projections for the second quarter in a row. We had an unannounced nonrecurring earnings pick up as a result of continuing diligent efforts to maximize the value of the southeast Saskatchewan oil properties we sold last year. We had an unannounced non-recurring earnings pick up as a result of continuing diligent efforts to maximize the value of the Southeast Saskatchewan oil properties we sold last year.

Coupled with the change in the Czech tax rate last quarter, that makes two positive surprises so far this year. And I am much happier with pluses than I am with minuses. Our utility apparition is quite close to our forecast so far this year, although it lags last year. On the other hand, despite our frigid recollections of January of 2004, this fiscal year as a whole has been warmer than last year, which accounts for some of the difference. Also, a large part of the utilities reductions from last year was due to charges for bad debt and post employment benefits. As a result of the rate settlement in New York. While they negatively effect this year's earnings, in the long run they're a step in the right direction. I remind you that last year we changed to a defined contribution plan for new hires and the achievement of a pension track, a pension expense tracker in Pennsylvania was especially helpful as well. Operationally, we got through the winter without any noteworthy events. While there was certainly high gas prices, our industry's previous years of experience with high prices enabled us to work closely with producers, marketers, pipelines and customers to provide the uninterrupted supply which our customers expect.

Exploration production is ahead of last year and Empire Pipeline and the Landfill Gas operations are both adding to earnings. Energy marketing and, of course, Timber are down from a year ago but ahead of our forecast. And overall reported GAAP earnings per share are ahead of last year. The rules for accounting for oil and gas activities continue to frustrate me. As a general proposition, I would like to recognize our problems and put them behind us and to that end last year we sold the southeast Saskatchewan oil properties and took a loss. This effectively reduced Canadian O&M expenses as Jim mentioned, but the various accounting rules left with us a Canadian full [INAUDIBLE] which exactly equaled our coverage test at September 30, 2003.

With the increase in prices, we have excess coverage at this point, with the additional $4-plus million dollars on the sales this quarter goes to non-recurring earnings, not to enhancing coverage. So the situation is such that if prices dropped below last year's levels, without substantial reserve editions, which could come from the [INAUDIBLE] we might have a writedown with respect to Canada. A writedown would, of course, be a non-cash item, whereas the additional $4.6 million in sales proceeds was, in fact, a real cash item. Nevertheless, it bothers me to have that uncertainty. On a happier note, I talk regularly with East Band and Nice Horse and they're committed to completing our project to connect our Empire Pipelines to Keyspan.

This supports my desire to expand our pipeline and storage segment and I'm very pleased with that. In a nutshell, this quarter is one more step, which helps to put us ahead of our schedule to improve our balance sheet and improve our overall returns on capital. I look forward to speaking to many of you at the AGA. this weekend and at this point, operator we will begin to take questions.

Ladies and gentlemen, if you do wish to ask a question at this time, please key star, 1 on your touchtone telephone. If your question has been answered or you wish to withdraw your question, please press star followed by 2. Questions will be taken in the order received. Please press star, 1 to begin. Please hold for your first question. Your first question comes from Devon Zahogan (ph) from Zimmer Lucas. Please proceed, sir.

Hi, this is Devon [INAUDIBLE] I want to clarify two points, you discussed the Canadian special reserve writedown. Can you go over that again? I didn't quite catch why you would need to write down your reserves.

We don't need to at this point. My point was that because of the rules with respect to accounting for the sale of our Southeast Saskatchewan properties, the consequence was that as of September 30 last year, the ceiling test EXEC gave us exact coverage of our full cost pool. In other words as of September 30, we had no cushion.

Oh, can I interrupt. I'm sorry to interrupt. What you're saying is you don't need to write down the MCFEs on your that you booked, you're talking just writing down cost full. (loud speaker) Is that right?

Yes, [ INAUDIBLE ] We don't need to do that at this point either. (audio difficulties) I'm saying we may have to do it if we have either -- well, if prices fall below last year's levels and if we don't have significant new reserves coming from the [INAUDIBLE] Well, which would increase the cushion we have today, then we could have a writedown. I'm not happy with the fact that as of September 30, we had no cushion. So we, you know, the cushion today is a result of the higher prices that we have experienced which, is a good thing, but on the other hand, we certainly learned that prices fluctuate wildly with respect to gas, in particular, and of course oil prices today are at unusually high levels, which is generating a substantial income that we're seeing from our E&P segment which, is good news. Sometimes I worry to much and sometimes I'm overly pessimistic, but seems to me we learn from experience the high prices don't last forever and we need to build our reserves in Canada or we're going face a writedown there. When prices fall.

Thank you, the next question is from Jim Harmon of Lehman Brothers. Please proceed, sir.

Thank you, good morning.

Good morning.

I've got three questions. The first -- I'll go one at a time. What commodity assumptions have you imbedded in your forecast?

Ron, why don't you answer that.

For the remainder of the fiscal year, our assumptions for our announced range, our gas prices of $5.10 to $5.35 per MCF and oil prices of $30 per barrel to $33 per barrel.

Okay. Thank you. Second question, Jim, for Jim Beck. You indicated that Gulf production volumes would be coming in in the third and fourth quarter, for that reason, you're pulling out, they seem to be driving your production now. Can you give us an idea what the decline would be given the volatile nature of those production volumes?

Yes. As you know, if you look at what we had forecasted in New York when we gave our presentations there, we had anticipated the Gulf this year to be between 21 and 23 BCFE and so the first six months we're at 14.2 and a lot of that is due to the 345 well that we brought on and the 252 well that came on and they all, both came on very good, actually, better than we had expected and so that's why right now we're seeing Gulf production significantly above what we had anticipated. You're right. The Gulf is very questionable. A well can water out and can you see a very significant drop in production. Right now, I would envision probably a 10% in the Gulf drop per quarter. Would be an average range, but it could be these wells continue to do well, it could stay up. You just can't tell with Gulf production. That's one of the questions, one of the reasons why we're transitioning out is that it's extremely variable. The other thing that can happen, can you have a hurricane shut in all of the productions for four, five days out there, which would impact you. So what we're just advising you is that we expect Gulf production to continue to drop, but we're still going to come in our range because we have seen consistency in both East and West and we expect Canada to start improving over the rest of the year.

Okay. Thank you. And last question is at the analyst meeting there was some, you know, indication that we might have good news coming out of the international segment, you know in regard to some new projects. Has there been any, you know, is there any update that you can tell us today?

At this point, we're not prepared to announce anything. We're still working away there on a couple of things. Hopefully next quarter.

Okay. Great. Thank you.

Your next question comes from Jay [INAUDIBLE] of UBS.

Good morning, I want to complement you for Larry, not a descent amount of hedges the past three months. Being greedy, I'm wondering with the current strip in outlook of gas and oil prices, are you putting on some more now?

We have put on quite a few as you point out, and we continue to put them on as our additional targets are reached. We had quite a discussion about this before as I recall. You're with the -- with the drop in the strip as you walked to the passage of time seems to permit you to layer in higher prices, particularly in the outer years, like '06, the oil prices in the outer years have come up quite a bit lately, and we're watching that very closely. You know, the usual combination of fear and greed. We had become more active in layering them in. We will continue to do so.

Okay, so going back to the utility, how you guys mentioned that debt expense rising, and I saw an article recently about a decent percentage of your customers having 30 days overdue or something like that, can you give us some data on where the rates stand, what percentage are your bills are 30 past days overdue where that compares to other standards and any efforts moving forward to be able to recuperate a higher level of bad debt expense going forward? Thanks.

Sure, I am -- the ultimate primary hovering mechanism for bad debt would be to a rate case unless we were able to sell that component in settlement discussions. But you're right, Jay. Compared to last year, and, again, I will just talk about the New York segment because that's the higher overall component of the utility segment. But last year at the end of March, about 78 to 79% of the receivables were current in that they were under 30 days. And then we had about 11% that were 30 days and then it trailed on off after that 4% over 60 days, et cetera. Currently this year, we have only got about 70% that are current and that -- 11% that I talked about in terms of being 30 to 60 days past due is up to 13% and then slight increases in all the other balances. What we're hoping to do again is through the summer, get more people on balance billing, get people into our consumer assistance offices to help them fill out their forms for keep allowances. We have been notified that the heap offices expect to stay open for the summer to allow emergency grants. Aside from that, there's nothing else we can do.

Okay, so there is no discussions with the commissions going forward about tracking, is that the case?

Oh, no, on the contrary. We're in confidential settlement discussions right now with the commission hoping to get something resolved, but as I mentioned, those are confidential and can't really say, by their nature, we can't say anything about them. But, it's in discussion. Certainly.

Okay. We'll wait and see what happens. Thanks.

Your next question comes from Phil Salles of Credit Suisse First Boston.

Thank you very much. It's a couple of questions. One on the efficiency gas. Could you give us the exact number on a pretax basis as to the amount of efficiency gas revenues in the quarter?

Sure. We certainly can. We're busy digging that out. We have an estimate here, how long it's going to take us to find that in this array of paper?

(audio difficulties)Just for the sake of time let me jump into some of the questions that I have for Jim. Jim last quarter you provided us some insights relative to the reserve additions and actually gave us that number which was on the plus side. Could you share with us the reserves for the [INAUDIBLE] quarter?

We discussed that at length trying to decide if we should do that again this quarter. With all of the concerns that have been raised about reserves and reserve addition, we really wanted to put out something that is audited. That the outside engineers had had a chance to review. We typically do not review those quarterly. That's done once a year and we're in the process of putting all that together right now for the year end review. So we felt that because of all the concerns we didn't want to put a number out that could change based on what our outside engineering group would come up with either positive or negative. So that's why we did not put it out this time. But we had a lot of discussion and felt it was better to be a little more conservative and make sure we had an engineer to prove number before we put anything out.

Can I then ask you based on what you've seen for the first half of the year, and your earlier comments, previous comments that will have some reserve adds for the year based on the drilling activity?

I think that's a reasonable assumption, as you noticed we did do an extensive amount of drilling both in Canada and in the East. And all of that development drilling, we had no PUDs, so anytime we drilled those wells we do add new reserves. And as you saw we had a high success rate in both of those areas. So you will see positive reserve from that drilling.

Ok. Part of your prepared remarks Jim was, was a comment that said, "there's no new offshore production expected to come online for the next six months." I was curious. Was that part of the plan, I'm thinking back to the analyst meeting and that little chart that you put up there with the yellow and red dots as far as the drilling activity. Is this a new comment or a new view [INAUDIBLE] of the second half. Is there some, I guess what I'm getting too, is there some drilling that gets pushed out to '05 or is this part of the current drilling plan as expected?

No, this is part of the drilling plan as expected. The wells that we had planned on coming on came on in the first quarter and so we've seen the benefits of those. Any new drilling, it usually takes 6 months to a year to get those wells online unless it's drilled on a platform. And the wells that we had up there for the drilling did not have platforms that we could be drilling off of, so it's all part of the plan.

And for those wells, would they add to reserves though? Or [INAUDIBLE] or what would be timing of those wells to add to the reserves?

Any wells under the SEC rules have to be tested to add new reserves. So if a well is tested then we could add new reserves. If it is not tested then we'd have to wait until we got a production test.

One last question. To the DD&A rate and the--was up sequentially as was the LOE. Could you just give us some insight to that and what we should expect for the second half of the year?

Ok, let's start with DD&A rates. It's been pretty consistent. This is what we had forecasted about a $1.47 I think is what we have forecasted last October and we're right in that range right now. And we expect that to hold to the rest of the year. As I said that last quarter, we came in very low in the first quarter on LOE on our Lease Operating Expenses. We were down in the 70's. I'd indicated that it would probably move up into the 80's. We finished this quarter at 80 cents. It looks like we're going to run in that 80-85, it'll probably be on the low side of the 80's rather than the middle as I'd indicated last quarter. And then GNAs is just about were we had forecasted in October right around 42 cents.

Very good, thank you as always.

I'd like to make one observation about that [INAUDIBLE] you referred to. As I recall the [INAUDIBLE] was in the right hand corner indicating there was reserve potential as well as [INAUDIBLE] That's still going at the present time. The results of that will have the greatest potential impact of any single well that we're drilling. As soon as we have some results on that we'll let everybody know.

Sure. And that would seem to be able to help '05 production as well.

Yeah, when that would come on production is a question I'd defer to Jim. Probably would have some impact on '05 production. [INAUDIBLE] I don't know what the plan would be as far as getting that production, once it is completed if it is successful.

The key there is that we work with Talisman (ph) who is the operator and as with all that production up there it has to go in and be processed and so we have to get it to a processing facility. Just depending on how the tests come out and what it looks like they seem to be very active and proactive in getting things done, so I know they'll try to get on as quickly as possible. I would envision it would have some impact on the 2005 result.

Thank you very much.

And Phil for the efficiency gas, for the first 6 months or year to date ended March for 2004, we had volumes of 1.977 billion cubit feet this year compared to 1.967 last year. And based on the pricing and the hedging differential, we were $1.8 million ahead of last year.

I was looking actually for the number in the current quarter for fiscal 2Q.

Ok. So for the quarter, volumes this quarter were 1.521 BCF compared to .911 BCF last year.

Ok. Thank you.

Your next question comes from David Maccarrone with Goldman Sachs. Please proceed sir.

Thank you. First, Ron can you just tell us what the expected tax rate for the year is?

Currently right now we're at about 38%. And I'll turn to my tax expert who is sitting across the table from me to see if there's any change.

We expect the year to have an effective tax rate of about 36-37% overall. And it's a little bit below where you'd expect because of the things still mentioned earlier. The reduction of the tax rate in the Czech Republic. And the adjustments we made on the Canadian sale. But again for the year we expect to come out with a rate somewhere between 36-37%.

For those who wonder who that is, that was Steve Wagner.

And then for Jim, I was wondering if you could give us some sense for what the potential reserve additions would be at West Cavern 96 and maybe there's a [INAUDIBLE] if there's been any disclosure of unrisked reserve potential or something to that effect and what your ownership stake is in each?

No. Since we're not the operator, we have not done anything with that yet and I think it's too early to say anything on 96 since the drilling is still going on. The [INAUDIBLE] it's a huge structure and as I said this third well was about a 6 or 7 mile stepout from the second well. And it really just depends on the test rates that we see on that well. And that's really what drives the results up there.

Ok. And what do you expect with Cavern 96 to be completed?

The ownership, you had asked 2 questions. One was the ownership and the other was completion. It should be down, we've got two wells out there and until we get all of the results in on both those wells we probably won't say anything. I would envision that it's going to be close if we can get it done this quarter. Our ownership position on 96 is we have a 25% backend with an option if we want to take it. On the first well and then on the second well, that is a unit well between two blocks and our ownership there I believe is 11.25%. And then on [INAUDIBLE] our ownership is 20%.

Ok. Thank you very much.

Your next question comes from Rebecca Followill of Howard Weil.

Hi. Just following up on that [INAUDIBLE]. What is expected TD? In a time to get the TD?

They've already changed it on us twice. And we are on the sidetrack right now and they're anticipated plan are to drill as long as they feel that they're seeing some positive results. And so we don't have a specific TD. They're drilling I believe at 4,750 meters right now.

And on the other two wells, what were the TD's on those?

On the Vermilian 96 well--

On the [INAUDIBLE]

Oh, they're about the same depth range.

Ok. So you should be fairly close then.

Yes, we are very close.

And then on Vermilian 27, same questions. What is expected TD and the time?

Ok. In the press release we announced that we had drilled the TD at some non-commercial hydrocarbon shows. And have plugged that well. So that well was one that we had really hoped for and didn't work out. And we were 50-50 on that well.

And then on [INAUDIBLE] 96?

Wescan 96 (ph) the first well is I believe is 16,000 on the first one and 17,500 on the second one.

And where are you now?

We're just proceeding on the drilling right now, and I'll have to get you--we'll get back with that information. We just wanted to report that as still ongoing.

Ok great. Thank you.

Ladies and gentlemen as a reminder, if you do wish to ask a question, please key star, one. We have a follow up question from Devon Zahogan with Zimmer Lucas. Please proceed.

Hi. Just 2 more questions. One is going back to the all system sales with issue with [INAUDIBLE] What would be the impact if you're unable to continue that [INAUDIBLE] and would you be able to go back to [INAUDIBLE]

Are we talking about the impact of the marketing affiliate rules?

Yes.

Yes. With respect to those offsystem sales there's a 90-10 sharing mechanism, 85-15, I'm sorry, with the customers or the commission and the company with the company keeping the 15. So the customer has the larger stake in that argument. We're working very closely with the New York commission, we want to try to accommodate the restrictions within the marketing affiliate rules of the FERC. Whether the state commission will bring an action challenging the order in court, or whether we will, rehearing or whatever hasn't been decided at this point. But the state commission, New York in particular is very concerned about the impact of that limitation. But I guess they get more to your question, there really would be no revenue requirement to us, to the extent we stopped, offsystems failed. It's really to the benefit to the customer [INAUDIBLE]

Ok. I guess [INAUDIBLE] is that one, you may have to stop the sales but two, you might actually have to separate the back office between pipelines and LBC which will cause an increase in expense. Is that something that you guys wish for? I'm just trying to understand the magnitude of this order.

Sure. I meant that's one component but again it is still mentioned any sort of cost related to that [INAUDIBLE] to continue the benefit to the customers.

Ok.

Devon are you all done?

Is that it?

I'm sorry my phone cut out. I apologize. And the last question, it's just going back to my first question. You're not referring to taking a reserve right down like El Paso or [INAUDIBLE] you're just referring to the cost pool?

Yes.

Like a balance sheet writedown. Ok thank you. I apologize for missing the [INAUDIBLE]. Thank you very much.

You have another follow up question from Jay [INAUDIBLE] of UBS.

Phil, here's a 50,000 ft one. On a recent call another CEO in the region acknowledged that there was just some increased chatter among senior executives about how companies might be better off down the road combining. Realizing you wouldn't be able to get into any specific, have you experienced this change in dynamic over the past lets say 6-9 months? And just overall what's your latest thinking on possibly combining or doing something with the company down the road? Thank you.

Actually I wouldn't say that I've seen or heard any significant increase in that kind of chatter. The discussions of combinations have occurred throughout the 30 years that I've been listening to that kind of thing and National Fuel is most--populous in this industry. The result of a combination of a great many companies over the years. It's effective life was in the utility industry and something that people think about all the time. Personally, I think that combinations tend to make more sense where the people who are combining are closer to each other rather than farther apart. Geographically and physically. And that's why I was particularly anxious to get a hold of the Empire Pipeline. Which I realized was the combination of the company, but not the sort of thing I think you're referring too. Synergies are just easier to achieve when you're closer than when you're farther apart, and that's the sort of thing I tend to favor. What matters is any discussion lately that [INAUDIBLE] four or five years ago has great potential for marketing other products and services through the active utility customer base. Some opportunities that some people took advantage of there, but I think those opportunities seems to be more significantly more limited than people talked about. I haven't heard much lately about there being some magic number of customers, utility customers that you need to have in order to achieve some magic, critical mass. That number seemed to escalate over the years. For awhile there's people, didn't achieve the Holy Grail or the critical mass of a million or 2 million so then it kind of escalated up but I haven't heard very much of that lately either. I think there are instances where you can achieve synergies. And I would continue to look for those. But I don't think combining for the sake of combining is a sort of thing that anybody's interested in anymore.

Ok thank you and we'll see you at the AGA.

Your next question comes from Mike Heim of A.G. Edwards. Please proceed sir.

I hate to ask a specific question after that 50,000, maybe a 5 foot question. In utility you talk about a decrease in margin, the 1.7 due to out of period regulatory revenue and gas cost adjustments. I'm not sure I understood what that means. Could we get a little bit more discussion on that?

Sure. The last--during the quarter last year, there was an allocation issue with some of the gas costs between the transporting, or between transportation and our sales customers, which was sorted out. This quarter, I mean if you have been following our rate cases or and settlements over the last couple of years, you realize we had bill credits of $10 million two years ago, $5 million a year ago and $5 million currently that needed to be passed back to customers. Once we have gone through a reconciliation of where we stand with passing those back, we have determined that based on lower usage per account than originally forecast we had not passed back enough of that bill credit to the customers. So it's really just cleaning those things up that got accomplished this quarter.

Okay. Thanks. That's helpful. On the marketing, there is a comment about marketing values being down to -- due to warmer weather. Can you just review again where your marketing operations is and why you're facing warmer weather for the marketing when the distribution space is colder?

I don't think the distribution is facing colder. Compared to a year ago?

Yeah.

Compared to last year, we were warmer than last year. Although, you know, colder-than-normal. I guess that's the distinction we're making, and it's the same residential customers that the marketer has, we're in the same service territory. I think what we talked about there was in the marketing segment based on more competition from other marketers. There has been a switch at the margin of some of those larger volume commercial customers from our marketing segment to other marketers in the area.

Okay, and also you talk about the losses from large customers. Is that any one type of customer?

No, it was just the sort of thing that Ron refers to, you know. A lot -- most of the largest customers bid out their supply requirements and sometimes you win the bids and sometimes you lose them. I don't think there is any particular type of customer that we're talking about there. It's just the size.

Okay, no one industry that is getting hit more or something like that that is moving away?

Oh, no, no.

Okay.

It's not lost in the sense it disappeared. It's lost in the sense that Ron referred to, that other marketers happened to win that bid that time.

Okay. And finally, just a reminder on the Empire and the North Winds timing, size, the Empire a new lateral or is that just adding compression?

The Empire connector that we're referring to is a new lateral that would connect the Empire line to the Millenium line or the Millenium route. Approximately going from Rochester, New York, to Corning, New York. And Millenium to go from Corning eastward to connect to the Keyspan system ultimately.

Okay. Have we said how much that's going to cost and when it -- when it might start?

We have. The number is about $80 million, I believe, for our connector part. And the target is to be in service for the whole project in our piece and the Millenium piece in November of 2006.

Okay. Okay. Thank you.

As a reminder ladies and gentlemen, if you wish to ask a question at this time, please press star, 1 on your touchtone telephone. You have a follow-up from David Maccarrone of Goldman Sachs. Please proceed, sir.

Thank you, I was wondering if you could tell me what the PP&E on the books is for the Canadian oil and gas business?

We can. We're looking.

We're looking it up right now.

And I'm not sure if can you answer this question without that one, but what is the sensitivity to the E&P/DD&A rate from a potential writedown if you change -- if you have a writedown related to a $1 decline versus that September commodity price in gas or oil. How that might impact the overall E&P, DD&A rate?

I can't -- I think I'm going to instruct my people not to answer the last one off the top of their heads. A much more complex calculation than we should hazard based on this.

Okay.

I think Ron has the total assets in Canada.

Yeah, for Canada, and again this is in U.S. dollars at the end of March, our net property plant and equipment is $132,566,000.

Okay. Thank you.

Ladies and gentlemen, this does conclude today's portion of-- today's question-and-answer portion of the call. I would like to turn this call back to Margaret Suedo for closing remarks.

Thank you, Rachel. We would like to thank everyone for taking the time to join us today. The replay of this call will be available in about an hour on both our website and by telephone. And both will return through the end of business on Wednesday, May 5. Our website address is www.nationalfuelgas.com. The telephone replay number is 1-888-286-8010, using pass code 77192977. We'll look forward to seeing many of you at the AGA conference, and this concludes our call today. Thank you and goodbye.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude your presentation, and you may now disconnect.