密歇根天然氣 (DTE) 2005 Q3 法說會逐字稿

Excuse me, everyone. We will now begin today's teleconference. All lines will be muted during the broadcast. [OPERATOR INSTRUCTIONS]. There will be a question and answer segment following the presentation. Instructions for asking a question will be given at that time. And as a reminder, today's call is being recorded. I'd now like to introduce today's speaker, Mr. Dave Meador. Sir, please begin.

Thank you, Carmen, and good morning. Let me start by welcoming you to our third quarter conference call. The slides for the call are located on our website if you don't have them.

And before we get started I would like to encourage you to refer to the Safe Harbor disclosure on page 2 and also encourage you to read our periodic filings with the SEC. During this call we will describe certain non-GAAP measures which should be considered in addition to but not in lieu of the comparable GAAP financial measures. With me this morning is our team, Dan Brudzynski, who's our Vice President and Controller; Nick Khouri, who's our vIce President and Treasurer; Don Stanczak, who's Direct of Regulatory Affairs; and Mike McNalley, our Director of Investor Relations.

I'm going to start on page 4 before I turn it over to Dan and provide an overview. Our underlying performance is on track with the objectives we laid out for 2005. This was led by an strong performance in both utilities year-over-year and the non-utility portfolio that is delivering on the goals we set out to achieve at the beginning of the year. In the spirit of transparency and because of the impact on both operating and reported earnings, we've laid out in detail the two areas that impact the third quarter earnings. The first area is the ongoing deferral of a portion of the synfuel earnings that we has talked through on the first and second quarter. It's a very similar situation there. And also the year-to-date experience on the mark to market on the oil hedges for the 2005 hedges, which we expect all of this to reverse in the fourth quarter of this year. And the second area we've also covered before relates to the transactions where we are economically hedge, but one side of the transaction is accounted for on a cost or accrual basis while the offsetting position is mark to market. We expect a good portion of this volatility will go away down the road as we look to shift our accounting starting with our next storage cycle and pursue cash flow hedge accounting. But until then we're living with the same accounting that we've had in the past. So there's really no structural difference than what we've had in the past. The only difference today is the impact on reported earnings has real really magnified based on what's happened to the gas and electric prices and the impact on the -- one side of the transaction that is mark to market. Dan will take you through that impact on the quarter, but also he will show you how we expect the locked-in economics to roll back into the income statement, not only in the fourth quarter, but also in 2006 and 2007. Without the situation where the accounting and economics don't match in the same time period, we would have hit our original guidance. We've called this out as timing because we are lowering our guidance because of this situation where you have year-to-date unrealized losses that won't reverse in the fourth quarter and some of it will carry forward into next year and the following year. And any short fall we're confident is an timing item that just gets retimed in the next two years. So that's why we framed it that way.

With that let me turn it over to to Dan who will take you through the details not only for the quarter, but also for the year.

Thanks, Dave. Good morning to everyone.

Let's move on to slide 6 and third quarter operating earnings. Operating earnings for the third quarter were $0.03 a share, significantly impacted by two timing related accounting items that David previously mentioned. Reported earnings per share was $0.02 and a reconciliation of reported to operating earnings which excludes things like nonrecurring items discontinued operations and the quarterly effective tax adjustments for both the quarter and year-to-date is contained within the appendix of the presentation. Primary contributions for the quarter were Detroit Edison at $0.55 and our non-utility power and industrial project segment at $0.27. MichCon had an operating loss of $0.09 a share due to the seasonality of the gas distribution business. Our fuel and transportation and marketing segment had a loss of $0.73 a share and this was where the timing relating accounting impacts due to the spike in energy prices as David mentioned this in the third quarter was felt. I will detail out those changes on an upcoming slide.

Continuing on to slide 7 and an look at quarter-to-quarter details by line of business. Beginning on the left with the third quarter 2004 operating earnings adjusted for the effect of tax rate impacts and the timing related accounting items that are similar in nature to the third quarter 2005 results, Detroit Edison and MichCon, our two regulated utilities, posted strong improvements quarter-to-quarter driven by sales and rate increases. Our non-utility businesses also had strong underlying performance when adjusting out the accounting related timing items of synfuel mark to market and the gain deferrals as well as the mark to market adjustments on our gas storage and power contracts due to the rise in energy prices as I mentioned. These are expected to reverse in the fourth quarter for synfuels when the average annual oil prices become more certain and upon settlement of the gas and power contracts later this year and into 2006 and 2007. And I'll cover that in an little bit more detail. As you can see, these timing items had a significant effect on third quarter earnings and really masked the strong underlying performance in 2005. Now, recognize these timing related items don't represent the entire universe of timing items in the business, just the more significant ones where the accounting and economics are mismatched.

Let's continue on to slide 8 and go through some of the details beginning with Detroit Edison. The electric utility's performance was up 35 million or 56% in 2005. Key drivers in the quarter were lower regulatory deferrals for stranded costs, offset by higher margins due to weather demand and the impacts of the November 2004 rate orders. However, this increase in summer demand also saw higher outage and restoration related cost due to more frequent wind and thunderstorms in our service territory. Also impacting the quarter was the discontinuance of merger interest billing which remained at the DTE Energy parent level. Continuing on to slide 9 and a little more detailed look at Detroit Edison's margins. As you can see on the left, margins were up 66 million after tax due to increased weather related volume as cooling degree days were 44% above normal and 65% above 2004 levels. Rate increases as part of the final orders added 18 million. Increased usage per customer in our residential rate classes added 15 million, and the impact of lower choice levels which were approximately 8% lower than last year. However, tempering the margin upside in 2005 was the impact of the caps on residential rates that remain in place until Jan 1, 2006 when the full PSCR mechanism will be in effect. These caps precluded us from recovering the incrementally high power prices due to summer demand. This mitigated the margin improvement by 42 million or $0.24 per share in the quarter.

Continuing on to slide 10 and MichCon's third quarter performance. Due to the seasonality of the gas distribution business the third quarter is typically a loss quarter. However, as you can see within our gas LDC, performance was improved from 2004 largely driven by the rate order impacts, higher storage revenues and merger interest billings remaining at the DTE parent level. So again improved utility performance in 2005. As a side note for MichCon, these operating earnings have been adjusted for the effective tax impacts and that reconciliation is contained in the appendix. If you recall, quarterly tax adjustments are made to true up earnings throughout the year to the projected annual rate and will net to zero by year end and has no impact upon annual performance.

Now transitioning on to the non-utility businesses in slide 11. As I mentioned earlier, strong non-utility earnings were impacted by timing related accounting adjustments that are expected to reverse in future periods. As we have mentioned in previous quarters, the mark to market changes of our oil contracts used to hedge our 2005 synfuel position will settle before year end. In addition, the continued deferral of the variable portion of synfuel revenues is also expected to reverse in the fourth quarter. The third quarter also saw, as David mentioned, large timing related accounting adjustments due to rising energy prices. As we have mentioned in the past where the forward hedge position of these contracts are marked commodity prices while the other side remains on a cost or accrual basis until settlement. The unusually high run-up in energy prices has widened this mismatch in our third quarter results. Moving on to slide 12 and more details on non-utility performance. Absent the timing related items, non-utility earnings are up over 2004 levels, largely due to increased synfuel production which was 27% higher over 2004 and the early contributions of our unconventional gas businesses. Again, as you can see on the right, the incremental timing related items had a sizeable impact to the quarter. It is also important to note that this misalignment in the accounting and economic margins on its own is noncash in nature and doesn't effect operating cash flows. I'll give you a few more details on this in some upcoming slides, but let me wrap up the quarter on page 13.

Our two regulated utilities posted strong results again in the third quarter as a result of warmer weather and the recent rate increases. Underlying non-utility performance was also up, but was masked by the timing related accounting adjustments. Now let's spend some time and go through these in more detail beginning with synfuels and oil prices on page 15. As we discussed throughout 2005, the variable portion of synfuel revenues has been deferred until more absolute certainty is achieved for this revenue recognition. We believe phase out likelihood in 2005 is low and given current oil price levels expect to recognize all of the deferred payments in the fourth quarter. In order to have a first dollar phase out in the very bottom threshold of the range oil prices would have to average $70 a barrel, or conversely, would have to average $145 a barrel for full phase out for the remainder of the year. On the cash front a significant amount of cash flow is projected over the next two years and as prices and markets merit, we'll be looking to further protect our future position.

Now continuing on to slide 16 and the anticipated mechanics of synfuels with no expected phase out. This summary lays out the various components of synfuel earnings by quarter for 2005. We have been recognizing the fixed portion throughout 2005 as they are received. The variable portions have been deferred and are expected to be recognized next quarter, resulting in an little under half of the total synfuel contributions to be fourth quarter loaded. At the bottom of the summary you can see this assumes a production level of 20 million tons.

Now moving on to the accounting impacts of our trading contracts in slide 18. As we have mentioned in the past as it relates to our gas storage contracts, certain energy trading contracts experience inter-period variability with commodity prices until the contracts are actually settled. But for some background on these contracts and the related accounting. Forward contracts are used to economically hedge certain physical and capacity contracts. However, the underlying accounting between the two sides of the transaction creates a inter-period mismatch. At contract inception a economic margin is locked in, and upon settlement of the contracts the accounting margin matches the economic margin. Over the time in between inception and settlement each side of the transaction has different treatments. The forward sale part of the contract is mark to market with commodity prices while the physical side of the transaction is not mark to market and remains on an accrual or cost basis until the contract is settled. Given the unprecedented rise in the third quarter of energy prices and the size of our merchant storage assets, this accounting economic mismatch was large. On slide 19, we have summarized the year-to-date impact and the projected retiming based on expected contract settlement. Year-to-date, the mark to market impact has been 202 million given the run-up in prices. About half of this change is expected to settle in the fourth quarter with gas withdrawals from the heating season and has no impact to the total year. The remainder of the realized earnings will be in 2006 and a small portion in 2007 related to certain power contracts. This flow back total and time table profile is known based on the existing contract structures, but the amounts could move with further mark to market changes before year end. So going forward, higher energy prices would translate into greater mark to market losses and more flow back in future periods. While lower prices would lead to lower mark to market losses and less flow back going forward.

Stepping back for a minute and reviewing these impacts in the context of energy trading's earnings contribution at longer term is on slide 20. When factoring in the retiming of the accounting margin of these contracts in 2005, you can see the impacts over this five-year time horizon. The combination of high energy prices and the decision to roll storage in 2005 based on favorable economics to the '05-'06 storage cycle changed the accounting economics earnings profile impacting both this year and future year's projections. Our current projection for 2005 in this business is a 30 to $35 million loss. If you were to adjust the amounts that were pushed to future years, 2005's performance would be comparable to prior years and to our prior guidance.

And now with that I'd like to turn the discussion over to Nick Khouri, who will cover cash flow and capital spending.

Thanks, Dan. Good morning, everyone.

Improved cash flow balance sheet strength remains a key priority for both management and the Board of Directors at DTE. And as expected cash flow so far in 2005 has improved from the levels of the prior couple of years. Turning to page 22, through September reported cash flow from operations was about flat from last year. However, reducing 2005 cash from operations is approximately 200 million of cash collateral resulting from commodity price increases. This cash collateral requirement is expected to be eliminated by year end through a combination of contract settlement and the use of letters of credit. Including net cash from the synfuel business, adjusted cash from operations is up about 14% from the same period last year. Totaling $844 million through September, up from 741 million in 2004. For the same year-over-year comparison, capital spending was up slightly, asset sales were slightly lower. In total, net cash after dividends and capital spending was negative to the third quarter. The fourth quarter is always a big net cash quarter for DTE. Consistent with prior estimates, before growth capital for the full year we are estimating positive net cash of between 0 and 150 million. The details of which are laid out in the appendix.

Page 23 details capital spending through September by business line. In total CapEx was up 66 million in the first 3 quarters of this year, reaching 709 million. The largest driver of higher year-over-year capital has been the redeployment of synfuel cash in the non-utility growth projects Totaling 92 million through September. The business lines with the largest growth capital through September were unconventional gas in the Texas Barnett Shale, in the powered industrial business line. Page 24 summarizes the underlying strength of DT Energy's balance sheet. Leverage is expected to again decline this year by over a full percentage point to 51.5%. Both measures of cash flow, funds from operations divided by debt and FFO divided by interest are also expected to improve. Finally, excess liquidity of approximately $1 billion remains more than sufficient given the recent nearly $2 billion bank credit renewal.

With that let me turn it back over to Dave to provide a overview of 2005 guidance.

Thanks, Nick.

I'm going to move to page 26 where I have a update on the guidance that I referred to at the beginning of the call. On the left-hand side is our previous guidance that we provided earlier in the year of $3.30 to $3.60 per share. As I mentioned without the accounting driven timing our guidance would have pulled up on the bottom end driven by the strong performance at Detroit Edison that Dan took you through. When you lay in the net unrealized losses that we will project -- that we project will remain at year end our guidance on the right-hand side is $3.10 to $3.30 per share. Of course when we get to year end we're going to have to help you through this. So when we report our year end earnings for '05 we'll show you the actual amount of this unrealized loss that we actually flowed back in the fourth quarter which reverses that amount that remains in 2006 and 2007 and help you through that on the guidance side. So our sense right now is that we would provide guidance in the mid December time frame and then we would be updating that for you in January when we do our year end call.

Let me quickly just touch base on page 27. Page 27 is the detail on the guidance for the non-utility business. Everything here remains the same with the exception of the trading and marketing line where you see the 30 to 35 million that Dan covered off.

On page 28, cover off our early thinking on 2006. As I mentioned we expect to provide guidance for the year in mid December which is after our Board meeting and when we can sit down and review our plans with them and then we'll update it at the year end call. And the update would be really on two fronts would be -- one would be to help you through the unrealized losses and what was realized in the fourth quarter versus what carries into 2006, and the other driver that we would update you on is the restructuring case at Detroit Edison. And as we learn more about that case as it gets finalized, is there a impact on 2006 over what we provided in our initial guidance. The key drivers and assumptions for 2006 include the utilities really having the foundation to return to their authorized return of 11%. We do assume significant stepup in our cost reductions for next year, and Gerry Anderson will cover that in much more detail next week. Also next week, Gerry will layout our progress in making investments in our non-utility businesses. What have we done year-to-date in the fourth quarter but how do we really see next year playing out and how do we see that growth happening on that side of the business going forward.

On page 30 and 31, let me summarize, and then we can open up for questions. As Dan laid out for you, the two utilities have shown significant improvement year-over-year and we expect that improvement to continue as we transition into 2006. Hopefully we've demonstrated the timing aspects of the economically hedged trading transactions and the fourth quarter expectations on synfuel revenue recognition. Nick took you through our cash and balance sheet metrics which were on track. And last, our guidance is being revised to $3.10 to $3.30 per share. On Tuesday at 10:30 Gerry Anderson, who was elevated to President and Chief Operating Officer of the Company this week, will present at EEI. That meeting, we will focus in on the stepped up cost reduction program that we're engaging on. So this is the Detroit DTE operating system. Basically we're taking that to an new significant level and we want to take you through our thinking on that. He will also talk through utility growth, which is something that we've been talking about recently how we see the utilities actually not only returning to financial health, but actually experiencing much higher growth than we've seen in the past and then our non-utility opportunities. And since we expect to cover those areas just in a couple days I ask that your questions this morning be limited to the quarter or 2005 activities.

And thank you again for joining us, and, Carmen, we will now open up for questions.

[OPERATOR INSTRUCTIONS]. Paul Patterson, Glenrock Associates.

Good morning, guys.

Hey, Paul.

Listen. I want to touch base with you on a 2005 item which came up earlier at the Michigan Public Service Commission. This SG&A investigation, so to speak, I don't know exactly how to describe it when they compared you with CMS, do you guys just have any sort of general thoughts? I know you've got 'til December to file something back with them, but I was wondering if you could share with us a little bit as to what you think is causing the difference and what have you.

I will start, then I'm going to ask Don Stanczak who's our director in regulatory affairs to help. My initial reaction is that it's really not a proper analysis to compare our A&G to Consumers. You're really comparing apples and oranges. We're different companies with different structures, and initial action is looking at a line item and declaring it high or low is not necessarily the best way to go about doing this. You have to look at A&G in conjunction with O&M and fuel and purchase power. hat being said, just wanted to point out that in the two rate cases that were finalized this year, the only disallowance in the rate case was merger related interests or A&G was accepted in both rate cases and we believe that our costs we can support. That being said, we plan on responding to the MPSC's request for more information. Don, do you have anything to add beyond that?

Not a whole lot. We did yesterday ask for a extension of 60 days and we are beginning to work a little bit with Consumers, but we're in the early stages of putting together the analysis and it's probably premature to go further than what Dave said.

Okay. And to the quarterly earnings, how much -- could you give us a flavor for the earnings impact actually associated with weather versus normal on a cents per share? You said it was 40% above normal, I guess, for cooling degree days but --

If you can give us two seconds, Paul.

And then year-to-date if you have it easily. If you don't we can follow up afterwards.

Do you have that handy?

Can I ask another question while you're looking for it?

Yes. Go ahead.

The -- I know you guys are 70% hedged for 2006 with respect to oil prices and synfuel. But I know that some of that actually involves previous credits that you guys have booked. Do you have any idea as to what the earnings portion of that hedge is? In other words, going forward in terms of the anticipated level of tax credits that you plan on booking, how much of the credits plan to be booked for 2006 are actually hedged, if you follow me?

The -- I think the rule of thumb when you look at our cash flows that we talked about is about 25% of the cash flows are tax credit carry forward utilizations. So the net amount is actually current year. And then so when we look at the percent hedge, we're -- what we're quoting is the -- it's the combination of what we have spent so far for the year to hedge and then also the tax credit carry forward utilization. And that's where the 70% comes from. But I can break that down for you.

Would that be the same for 2007, so if we were to look at the 2007 you say 25% that basically without the -- leaving out the tax forward -- carry forward -- tax credit carry forward, would you be essentially unhedged in '07?

No. No. We are actually stepping into hedges for '07. And we have spent additional moneys for '06 and we are spending money now on '07. So the -- when we're giving the percentage protected it's the use of that tax credit carry forward plus we spent a little over $30 million on hedges for 2007.

Okay.

Paul, this is Dan. Just getting back to your first question, weather for the quarter had about a $0.37 pickup versus last year, which was probably a little bit -- a portion of that is due to weather being below normal last year. But the majority of that is just being above weather normal. And that would be a good approximate for the full year on the electric side. But you would need to net against that, though, the impacts of the residential rate caps which is the negative $0.24. So as I would like at quarter from a weather standpoint, it would be a net $0.13 pickup.

Great. Thanks a lot, guys.

Yes. Thank you.

Paul Ridzon, Key McDonald.

I was wondering if you've given any thought to kind of recasting the way you give guidance to kind of strip out the mark to market. And then in '06 and '07 what percent of the volumes are going to settle in '06 and '07?

Well, in regard to your question on how we think through guidance, actually my preference is actually to try to pursue an accounting change that -- there is a possibility on a subset of these transactions to pursue cash flow hedge accounting and then we won't have the situation where you have half the transaction marked, half not marked and that -- and reduces to a much smaller number. We've always included this in operating earnings and we might call it out separately. But it's just become large enough now with gas prices where they are that we've had to layout the timing items. But on your second question on the timing, you were asking for the flow back by year? Paul?

Post '05, falling into '06 and '07?

Yes. That's really on page 19 of the presentation. That if you look at our year-to-date unrealized losses that we've accumulated it's 202 million. We expect at current gas prices that 116 of that will reverse in the fourth quarter and then 65 million in '06 and then a smaller portion in '07.

And what's the price of natural gas embedded in the most recent guidance?

All this is done at the current forward curve.

Okay. Thank you.

Steve Fleishman, Merrill Lynch.

Hi, Dave.

Good morning.

Just -- I don't know if this is off what we can ask now. But you mentioned cost cutting efforts. And obviously the rate to skewing outcome. Are those both targeted at achieving your allowed rates of return of 11% in '06 or are those things that would potentially even allow you to achieve better than that? How shall we just think about that?

It's a good question. The -- we have, I think, been pretty consistent to say in achieving our goals for 2006, the drivers are going to be the economy, the rate restructuring case at Detroit Edison and then cost reductions. The rate restructuring case, even though we are optimistic that that's on track and you've seen not only the Staff filing but also the administrative law judge, that's going to play out here over the next 6 weeks. We still have looked out at the horizon and for a lot of reasons have determined that we want to take costs out and the efforts are well underway and I think Gerry will go into some detail. And what we're really trying to sort out right now is how much of that will play out in '06 versus '07. To your question to is it possible to overearn? I think anything's possible right now. Our sense is that that's not in the cards for next year, that we would target 11% and we think we'd be within an reasonable bandwidth around that.

Okay. Thank you.

Okay.

Philson Yim, Morgan Stanley.

Hi. Good morning.

Good morning, Philson.

In the impacts of the residential rate cap, the negative $0.24 to electrical utilities, how much of that was related to firming and how much of that was just being short in the summer?

The -- you've got to look at it in total. So initially I think you could react and say the fact the firming went down and we had to buy more purchase power. It could play into that. But the reality is the way it works is you more than make that up through wholesale sales and by the time you get to the end of the year I think where you end up net out to say this is just weather driven -- weather and power prices driven is how I would describe it.

Right. Okay. And you had mentioned that the utilities are on track to earn 11% ROE in '06?

Well, the words that we're using, and it's -- we have the foundation in place with the two rate cases behind us. And as I was just mentioning to Steve's comments, we've always said the economy is soft in Michigan. We have the rate restructuring case that we have to work through and that -- that'll play out in the next six weeks, but it always believed that we were going to have to take out cost as a way to earn our authorized return. So we started on a cost reduction initiative some time ago. I think we really got traction going back 6 to 9 months ago to make sure that we had enough lead time to be able to deliver on our commitment to the shareholders.

Great. Thanks very much.

Okay. Thank you.

Nicholas O'Grady [ph], Sandell Asset Management.

My question has been answered. Thanks.

Okay. Thank you.

Bob Warren [ph], Bear Wagner.

It's Andy Levi. The only question I got left is can you give us any guidance for the fourth quarter?

Well, it's really the 3.10 to 3.30 minus our year-to-date earnings. It's not much more than that. The reason there's -- you have this range and a couple things to think about is, Detroit Edison has had a unusual number of storms this year. So when we forecast we forecast weather normal. So if you have -- if you have a cool fourth quarter here, that can help. But storms are always an issue with the electric utility. And then this unrealized mark to market gain that we've talked about is sensitive to gas prices. So if gas prices go up $2 that could actually make the mark to market loss worse. If it goes down the opposite will happen too. This whole timing issue that we've described I can describe the physical side of it, but until the gas is withdrawn from storage it's exposed to mark to market movement caused by commodity price movement.

What shall we be using for year-to-date from that 3.10 to 3.30, the 9 months?

It's in the slides on page 46. So -- the fourth quarter number is around $2 per share if you take the number and back out our year-to-date results.

The fourth quarter should be about $1.10 to [inaudible] --

No. It should be around $2. It's the opposite. Our year-to-date is $1.14 --

Oh, I thought you said it was $2. Okay.

And then the fourth quarter, it's going to -- it's $1.95 to $2.15.

Okay. I got it. Thank you.

Thank you.

David Thickens, Deephaven Capital Management.

Good morning.

Good morning, David.

A couple of questions. Can you give us a little more color on the potential change in accounting treatment to allow you to better match the -- or avoid the timing mismatch? I guess the question is, if it's something you're considering and looking at doing, what has prevented you from adopting those accounting principals already?

Just to back up a little bit, the -- given the history on mark to market especially in this industry, the SEC and the FASB, but the SEC in particular has been pretty firm in terms of what could qualify for hedge accounting and what will not qualify. And in the cash flow hedge treatment space, it's -- there's a very narrow definition of what can qualify. You have to -- at the time you do the transaction you have to not only determine that you want this treatment but there's a lot of documentation that you have to go through. So we have been working through this issue as others have been in the industry. And you have to really wait 'til your next roll on of storage happens. So for example, the current transactions we will let play out, and then we will look to adopt cash flow hedge accounting where it's appropriate. And do that with the next cycle of transactions. So you have to do this when you contract, and that's part of the issue.

How much -- could you give us an idea of what proportion of these current -- or these current mismatches could have been avoided had you adopted this when you put them on? Because the reality is kind of the magnitude -- if your magnitude was half it's still half of what you reported here this quarter. It would still be a fairly significant amount and still be causing choppiness that you'd have to explain.

Right. The -- in the past, our trading operations where this resides on an accounting basis -- accrual accounting basis has had relatively steady earnings in the 25 to $30 million range. In the past when we had not had the hedge accounting for the storage in particular, we've said based on the historic gas price movements you might see a 10 to $20 million mark to market movement. This has really been exacerbated with current commodity prices. So if we had cash flow hedge accounting for this I would -- I'm just going to take a rough guess to say two-thirds of it might be gone but you could still have situations where you don't meet this very strict definition. You could have something that's economically hedged, and that's one of the things I just want to be really clear about is you can be economically hedged and not qualify for hedge accounting under the very strict rules. So our challenge here is that as a Company we've always said we want to be value focused. We're going to drive for values in underlying economics and not chase quarterly accounting earnings. I know that's frustrating when you see these types of numbers flow through the accounting statements. But we're confident that this economically locked number will flow back and then we -- with the next cycle, we are going to do everything we can do to pursue the accounting shift on this.

Well, I would -- thanks for the explanation. I would just reiterate what Paul said and maybe urge you guys to consider giving some kind of forward guidance breaking the hedges out just so that the market gets a -- people who read headlines get a clearer view of your actual earnings power. The other question I have is, can you give us any kind of update on your progress in the Barnett Shale? We've seen quite positive results from a number of the other operators down there making wells significantly better than expected. Can you give us -- do you have any well results you can share with us or tell us kind of what you've kind of completed to date?

We do. And I don't want to be difficult about this. Gerry Anderson who's, as I mentioned, our President and COO is going to be at EEI. His presentation will be webcast on Tuesday morning at 10:30. And that is a fair amount of his presentation as we get into what are we doing to grow all three segments of our business where we're driving to scale. And he has an update on the two pieces of Barnett. Because with Barnett we made a acquisition this year that has producing wells and then we continue to make progress in the southern acreage where we're doing testing and drillings. And Gerry will have new information and provide that -- the statistics and numbers and so on on Tuesday. I just don't want to preempt him.

Fair enough. Thank you much.

Zack Schreiber, Duquesne Capital.

Hi, guys. It's Zack Schreiber from Duquesne. Can I hear me?

Yes. Hi, Zack.

Hi. Just a question on the rate, the skewing case, and if you could do our work for us and remind us what the ALJ recommended, what the ALJ proposed and what the Staff recommended?

I'm going to turn to Don for help on this.

The ALJ proposed that all customers pay the same distribution charge, which is whether they're on choice or not which is what we proposed, what Staff proposed. Relative to how the subsidy is dealt with, you may have heard us call it the regulatory adjustment charge or RAC?

Yes.

The judge proposed that it be split between generation and distribution. Now, we had proposed that there's a uniform RAC for all customers, and that it's -- whether you're on choice or not you pay the one uniform RAC. The judge proposed splitting it between generation and distribution and therefore you would get out of paying the generation piece if you went to choice. Now, interestingly, in the Consumers rate case which is basically at the same stage and deals with the same issue, the ALJ proposed a uniform RAC. The judge also proposed the five year phase out of the RAC. We had proposed five years beginning 1-1-07. Staff had proposed 10 years. And probably the last real issue was kind of an technical rate design issue. Staff proposed a slight modification from the historical cost to service rate design model. We proposed staying with the traditional model the Commission used in the past and the judge agreed with us.

Okay. And we should expect the final decision on that in six weeks, you said?

Where we are in the case, we file reply exceptions to the judge's ruling on the 10th and then it goes to the Commission. So sometime subsequent to the 10th.

Great. And just following up on David Thickens' questions, on the Barnett shale, is there anything sort of new that we're going to be hearing at EEI? Is that more sort of towards the December or January meetings? Having just met you -- with you guys at the Merrill Lynch conference my sense was it was more towards the later year -- part of the year. I just wasn't clear on that.

There's really two pieces to this. So the acquisition that we made, which is in the northwest area of Fort Worth where we have actually producing wells. I suspect there's more detailed more specificity in terms of what's producing this year, how many wells we're going to drill next year. The southern acreages, I think as you're describing it correctly there are a little bit more information. But this is something that every quarter as we continue seismic testing and we drill more wells and others drill more wells in the area, the intelligence around that is going to get better each quarter. It's not -- there's not a step function change where we're going to come out one day and say we drilled 50 test wells and we now know everything we need to know about the southern acreage. I think the information for this is just going to get better each quarter that goes on. So a little bit on the southern acreage. And then I think when we talk to you in the first quarter, we'll have more and so on during the year next year.

Got it. And then just on these -- on the synfuels and just to make sure I understand to be able to put the hedging that you guys layout in terms of cash impact, is the synfuel cash you expect still roughly like 450, $500 million an year '05, '06, '07, '08? And when you say 70% hedged is that on a earnings basis or was that on a cash flow basis such as that the 30% is on $125 million or something in the 70s. I'm just trying to understand that. And then related to the hedging, what kind of structures can you be putting in place now where you're spending money now to hedge it? Are you paying a lot of option premium now because those options have a lot of intrinsic value given where oil prices are, or are there more creative sort of zero cost options that can get you a lot of notional protection without too much option premium outlay?

Well, the -- I mean, the cash numbers that you described are the same cash numbers.

They are? Okay.

When we talk about hedging we actually -- what we're talking about is cash grow protected when you give those percentages. Because as I spoke earlier we have the tax credit carry forward that we -- that's now an AMT carry forward that it's really indifferent to this whole issue of oil prices and phase out. So we get that and then we're entering into hedges for the underlying incremental synfuel cash flows for that calendar year.

The -- in regard to your question, we monitor the market. We're looking for price dips. I gave a new number for the 2000 hedges. We're not doing anything unusual there. These are average year options where we are basically looking for opportunities in the marketplace. So in the last several weeks, for example, there were opportunities for the 2007 year. We've kind of set some parameters to say -- and I won't disclose how much, but we set parameters to say in some cases I would be willing to spend a certain amount of money that would give me a 2 to 1 benefit. I'm certainly willing to spend a lot more money if it's 3 to 1 or 4 to 1 or 5 to 1. So as oil prices move around we will take advantage of that from time to time.

On the weather benefit, I think you said that was -- was that $30 million? But then that was offset by the residential rate squeeze, if you will, as those guys still be subject to the residential rate freeze. What was the net of that on a quarterly basis and on a year-to-date basis? Just make sure I got that down right.

You're looking for margin net of the residential or weather net of the residential?

Looking at the sort of weather impact versus normal and then sort of adjusting it for the negative on the residential rate squeeze.

Well, the quarterly basis is on page 9 where the weather was 66 million you could see --

But that was versus last year, and last year was milder than normal.

Oh. You're looking on an absolute basis? We'll have to get back to you on that, Zack. Everything at hand is year-over-year here.

Okay. Was there anything else here? Where are we on the stock buy back?

Well, right now we're still in the same position we took earlier in the year that we see investment opportunities in hand that I don't anticipate doing a stock buyback. Our year-to-date capital spending in the growth areas is over $100 million. Gerry will provide some updates on things that he sees happening in the fourth quarter of this year and early next year. So right now, in the three areas of focus, the power and industrial, unconventional gas and then the fuel marketing and transportation, we see ample opportunities that can earn returns much higher than a stock repurchase.

Got it. And the last question is -- I missed this. You were talking about free cash flow for the year and you gave the 9-month numbers. Was it 100, $150 million positive or negative on free cash flow for the year?

Zack, this is Nick. On page 40 in the appendix it is actually the full 2005 guidance. And you'll see that 0 to 150 million positive for the year.

Got it. Guys, thank you so much. And look forward to seeing you next week.

Okay. Thanks.

Stuart Bush, RBC Capital Markets.

Hi. Good morning.

Good morning, Stuart.

I just had a few quick questions to clarify. On your synfuel you mentioned that when you give your forecast guidance for 2006 at 100% of synfuel revenues -- or earnings will be recognized. That's a combination of either production or hedges and AMT, is that right?

It is. But let me just clarify. We've said 100% -- the way it's working out for 2005, 100% of cash flow. And close to that in earnings. When you go out to 2006, it's 70% of cash flows and that's a combination of what you describe which combination of hedges and/or the use of the tax credit carry forward. And it's a lower amount on earnings for next year. So when we say the numbers that we've been quoting in the past it's always been on a cash flow basis. And the reason is this -- these cash flows expire in several years and we believe the right way to look at this business is on an net present value of cash flows between now and early 2008. So we've always been talking about hedges in terms of cash flows protected.

Okay. Assuming that the oil prices do not reach the lower band and you are able to produce, do you give guidance on what you expect production levels to be? Or will you give guidance in '06 over '05?

Right now the base assumptions is that production levels would be similar to this year. So we were looking at 20 million tons a year. When we provide guidance and then again when I update guidance at our year end call, depending on where oil prices are if we have any new insights into prices and the potential impact on production we would update you at that point in time.

Okay. My last question is just along those lines, looking at the band of where the phase out occurs, if there -- have you -- what level does the -- within that band does it need to be before it starts to really impact production? I assume that if it's just slightly impacted on the phase out, then you can go ahead full 100% production.

Well, the difficulty here is that you're dealing with a average calendar year number.

Right.

So for example in 2006, if the lower band is projected to be $59 and it's early in the year and you're close to $59, it's a more difficult call than later in the year when you already have a lot of your actual average behind you and you can kind of get a sense about what is the risk level I'm taking. So I think the right way to go about this is when we do our year end call in early February we'll have a real sense of where we are for the year's projections and what the forward year is and any thoughts that we might have on production.

Okay. So but I'm -- I just -- I assume that between that 59, 25 and 73 there's some price point within there where it doesn't make it economical to continue production. Is that right?

You're right. Well, it could. It depends on how the year works out. The issue would be early on are you willing to take risks at the higher level because you incur net operating losses that you might not ultimately recover. Are you willing to take that risk early in the year believing that oil prices will come down. There would be some level that you might curtail production. And again, I think instead of dealing with a hypothetical example, it would be much easier when we get early in the year if oil price prices are at the level that they are now to talk about how do we think about production.

Okay. Thank you so much for your time.

Okay. Thank you.

Shar Khan, SAC Capital.

Good morning, David. How are you doing?

Good. How are you?

Pretty good. David, I did some analysis I kind of shared with our IR team. And could you just share with us first, what is the average employee wage at the utility companies? And my second question is, I found that your office and supply line was pretty high versus some of the comps that I did with the other companies which are in the metropolitan area. So I was wondering if you could a little bit mention what is in your office and supply -- I think the perk form showed was like a 77 million number. And so I was trying to get some kind of a thing on that as to and where the cost reductions in which areas are they focused towards?

In around to your first question, I don't have that number in terms of a average employee that would work in the utilities. There's a wide range from summer high school students all the way to people that have worked here for their whole career, 35 years. So I don't have that number that handy.

Okay.

In regard to the office supplies and other elements of the A&G request that the MPSC has made, I think it would be not appropriate to comment on that. We're going through our analysis and we are also looking at other companies and I think when we respond to the MPSC that would be the time to talk publicly about that. In regard to cost reductions, and I don't want to preempt Gerry on Tuesday, but we are looking everywhere in the entire organization. So this would be our fossil plants, nuclear plants, both distribution companies, gas and electric and corporate staffs and we're looking at a wide range of alternatives and opportunity. And basically looking at not only possibilities to reduce O&M, but to reduce capital and to reduce fuel purchase power. I think good cost reductions that get passed on to customers are good cost reductions. So we're targeting everything. And then Gerry will go into more detail next week.

Okay. And, David, I just wanted to congratulate, I guess Gerry's not on the line, but the whole crew who got promoted in the last couple of days.

Thank you. I think it's a good comment. And one of the things that we have been working on is creating scale and focus. And as you do that we wanted to make sure that we had the right leaders or the right combination of leaders in the businesses to drive the results that we want to bring forward, including these cost reductions.

Okay. Thank you.

Thank you. I'll take one more question.

Gregg Orrill, Lehman Brothers.

Good morning, Greg.

Thanks. Good morning. Is there a test year in the SG&A filing you're going to make?

It really doesn't have that type of a concept. It's not -- Don, why don't you explain?

Well, the Commission compared 2004, so -- and that is obviously the most recent year that's available so.

But you wouldn't update that?

Probably will not have that -- well, we won't have that data available before we respond. We won't have '05 available before we respond.

Okay. Good enough.

Okay.

Thanks.

Thank you. Well, thank you for joining the call. And we look forward to seeing everybody at EEI, and for those of you that won't be able to attend, I encourage you to listen to the webcast call at 10:30 on Tuesday morning. Thanks again.