埃特莫斯能源 (ATO) 2005 Q3 法說會逐字稿

Welcome to the Atmos Energy Corporation third-quarter earnings conference call. At this time all participants are in a listen-only mode. Following today's presentation instructions will be given for the question-and-answer session. (OPERATOR INSTRUCTIONS). As a reminder, today's conference is being recorded Tuesday, August 9, 2005. At this time I'd like to turn the conference over to Ms. Susan Kappes, Vice President of Investor Relations.

Thank you for joining us. This call is open to the general public and media but designed for financial analysts. It is being webcast live over the Internet. We've placed slides on our website that summarize our financial results. We will not review those slides in detail, but will be happy to take any questions about them at the end of our remarks.

If you would like to access the webcast and slides, please visit our website at AtmosEnergy.com and click on the conference call link. A recording of this call is available for replay on our website through November 8, '05. Also, we plan to file the Company's Form 10-Q later today.

With me today are Bob Best, Chairman, President and CEO, and Pat Reddy, Senior Vice President and CFO. There are other members of our leadership team here to assist with questions as needed.

As we review these financial results and discuss future expectations please keep in mind that some of our discussion might contain forward-looking statements within the meaning of the Securities Act and the Securities Exchange Act. Any forward-looking statements are intended to fall within the Safe Harbor rules of the Private Securities Litigation Reform Act of 1995. With that I'll turn the call over to Bob Best who will review the highlights for this period.

Thank you, Susan, and good morning, everyone. We appreciate you joining us this morning and appreciate your interest in Atmos Energy. As Susan mentioned, Pat Reddy, our Chief Financial Officer, will review the financial results in just a moment; but before Pat does that I want to mention a few points about the quarter and the year.

Yesterday after the market close we did report net income in the third quarter of fiscal year 2005 of 4.5 million and 153 million for the first nine months of the fiscal year. For those first nine months net income was split about 68% from the utility segment of our business and 32% from our non-utility segments. Earnings per diluted share was $0.06 for the quarter as compared with $0.09 a year ago and for the nine months diluted earnings were $1.94 a share compared to $1.78 for the prior nine-month period. However, I should mention that the prior periods did include the impact of nonrecurring gains on the sale of an office building and our indirect interest and Heritage Propane Partners.

Yesterday our Board of Directors did declare our 87th consecutive cash dividend and our indicated dividend rate for fiscal 2005 is $1.24 a share. We mentioned in our press release net income for the first nine months was negatively affected by about 20 million or $0.26 per diluted share because of weather that was 11% warmer than normal as adjusted for jurisdictions who have whether normalized rates.

The weather has impacted our financial results this year and our two largest jurisdictions which do not now have weather normalization provisions in their rate structures and those are Mid-Tex and Louisiana. These two jurisdictions combined have about 1.8 million customers or 58% of our total customer base. And we do remain focused on pursuing rate designs such as decoupling our margins from our customer usage and recovering the gas portion of our bad debt expense and I'll talk more about that later in our presentation.

Despite this warmer than normal weather and the impact that it caused, it's important to note that we were able to offset most of the negative effect of mild weather. This was achieved by our enterprise wide cost containment, but more notably and more importantly we have accelerated about 20 million of operational synergies from TXU from the TXU Gas acquisition that we originally expected to come into income in 2006. This equates to about $0.16 per diluted share we realized ahead of schedule.

We certainly remain extremely satisfied with the performance of our new Mid-Tex Division and our Texas -- and our Atmos pipeline Texas divisions. Combined these two new divisions delivered about $0.02 per share in the third quarter and about $0.14 per share in the first nine months and we certainly feel that we are realizing the benefits we articulated to you when we made the purchase of TXU Gas. We continue to unlock the value on the new intrastate pipeline or Atmos Pipeline Texas and Pat's going to talk -- will give more detail on that in his part of the presentation.

Our natural gas marketing segment continues to deliver solid results; that segment added $0.03 per share in the quarter and $0.25 per share in the first nine months. Additionally we used excess cash to redeem five series of our first mortgage bonds at the end of June and in the aggregate we reduced debt by approximately 72.5 million.

As you know, when we acquired TXU Gas we financed the transaction with two successful equity offerings that raised about 618 million in net proceeds and we also sold 1.4 billion of senior notes. We've had a solid track record of bringing debt to total capitalization back down after we make an acquisition to the range of 50% to 55%. And for the nine months ended June 30th our debt to capitalization ratio was 57.5% as compared to 59.7% at December 31.

Finally, I'd like to just mention the passage of the Energy Policy Act which was signed yesterday by the President. While it's not going to immediately lower gas prices for our customers, we think long-term it will have some significant impact for our Company. For one, it does encourage new investment in natural gas pipelines to bring more supply to consumers and to improve reliability which, again, we expect longer-term the provisions in the bill will help lower prices for consumers. It lowers the depreciation rate on distribution systems from 20 to 15 years which of course will help our cash flow, and it does contain many provisions which will help move current production levels up.

One disappointment for us is nothing was done for the moratorium on the offshore drilling, but of course there are some provisions in there which give the FERC exclusive jurisdiction over LNG terminals which will help bring more gas into our country over time. And it does raise the funding on Lihead (ph) from 2 billion to 5.1 billion which, again, will help our low -- it helps us in that it helps our low income utility customers to pay their energy bills and reduces our write-offs for bad debt. So all in all there are many good provisions in the bill and, as I said, we are very hopeful that long-term it will have a positive impact on our industry and ultimately on our Company.

Now I'm going to turn it over to Pat Reddy for his comments and then when Pat is finished we'll conclude and open it up for questions. Pat?

Thank you, Pat, and good morning, everyone. Since our fiscal third quarter is by and large a loss or breakeven quarter for us, I'll speak to the more significant items in the quarter and then turn to the nine months and end with some color around where we think we'll be at year-end. I'll begin by first mentioning that our average number of shares outstanding increased significantly as a result of the equity issuances that Bob discussed to help fund our TXU Gas acquisition. Shares increased by 27.5 million quarter-over-quarter and by 26.3 million year-over-year. The higher number of shares, of course, influence our EPS calculation and just needs to be kept in mind.

Net income for the quarter was 4.5 million compared to 4.8 million a year ago, and for the first nine months of our fiscal year net income reached a record 153 million compared with 93 million for the same period a year ago, an increase of 65%. Earnings per diluted share for the quarter were $0.06 compared with $0.09 the same period a year ago. Earnings per diluted share for the current nine months were $1.94 compared with $1.78 in the prior year or an increase of 9%.

As Bob mentioned, last year's earnings per share were positively impacted by $0.02 in the quarter and $0.08 in the nine months ended period from the gains associated with onetime transactions. If you back out the effect of these nonrecurring gains in the nine months net income rose 72% and earnings per share rose 14%.

Consolidated gross profit for both the third quarter and nine months ended periods essentially doubled. For the quarter it reached 224 million compared to 107 million in the same period a year ago and for the nine months ended consolidated gross profit reached 927 million compared with 473 million a year ago. Utility gross profit for the quarter was 175 million, up 82 million from the prior year period driven primarily by the contribution from the new Mid-Tex Division which delivered gross profit of 79 million and 29 Bcf in incremental throughput.

For the current nine month period utility gross profit rose to 756 million or 79% from the prior period. The strong increase is due to 325 million of gross profit contribution and 151 Bcf in incremental throughput from our Mid-Tex Division. For the historical Atmos fixed utility divisions gas throughput was about 201 Bcf down slightly from 208 Bcf in the prior year period as a result of the effects of warmer weather during our heating season.

For the nine months weather was 11% warmer than normal across our system and, as Bob mentioned, this negatively affected net income by over 20 million or $026 per share for the current nine-month period. Our natural gas marketing gross profit for the quarter was 10.4 million, down slightly from the prior year quarter but was up 7.4 million for the nine months ended compared to the prior year period. The quarter included a 2 million increase in unrealized mark to market losses on storage financial instruments due to an unfavorable move during the quarter and the forward indices used to value the storage financial instruments as compared to the prior year quarter.

However, for the nine months ended the marketing business experienced a 7.4 million decrease due to an increase in unrealized mark to market losses and had a 9.8 Bcf increase in gas storage quantities. With the higher amounts of physical storage volume the marketing group was able to capture arbitrage spreads in a somewhat volatile market and increased their contribution by 8.7 million for the nine months. Additionally for that period, natural gas marketing had a 6.8 million increase in realized natural gas marketing contribution due to higher margins realized on increased volumes of 6 Bcf sold over last year.

As we talked about on our prior call, we acquired 9 Bcf of additional storage in fiscal 2005 and we had the expense associated with this incremental capacity during the quarter. As a result of this additional storage we can expect the potential for increased volatility in our margins going forward. In an effort to provide more transparency in this business we now quantify the embedded value of our storage book in our 10-Q and also in the appendix to this slide presentation.

This slide shows the difference between the economic value, which is what we use to manage the business, and the GAAP reported value at the end of the reporting period. We define economic value as the difference between the weighted average storage price less the weighted average cost of gas of volumes and storage. At June 30, 2005 the economic value of gas held in storage was 18.1 million whereas the gas value recorded in unrealized trading margin -- excuse me, our economic value of gas held in storage was 18.1 million whereas the GAAP value recorded in unrealized trading margin was an unrealized loss of 8.4 million, yielding an embedded storage trading margin of +26.5 million. The recognition of this 26.5 million in earnings is currently expected to straddle three fiscal years and is dependent on executing our planned withdrawal and injection schedule from which these values are derived.

Turning to our pipeline and storage gross profit, we recorded over 38 million in the third quarter, an increase of 36 million from the prior year quarter and with 122 million for the nine months ended an increase of 113 million. The significant gross profit increase is a result of 255 Bcf of incremental pipeline transportation volumes from the new Atmos Pipeline Texas division. We continue to unlock the value of our Atmos Pipeline Texas division as demonstrated by the high volumes transported on the pipeline during the period. Let me give you an update on the projects that we are developing.

We announced our transaction with Energy Transfer Partners last quarter; we signed a letter of intent to jointly construct, own and operate a 45 mile, 30 inch natural gas pipeline in the high-growth area just north of the DFW Metroplex. This solves deliverability issues for the utility and creates commercial opportunities for the pipeline. This pipeline will allow us to serve between 100,000 and 200,000 new customers in Collin County which is one of the fastest-growing counties in the United States. And from a commercial perspective, the parties continue to negotiate with interested third party shippers.

We are close to completing the final agreement with Energy Transfer and while this process has taken longer than expected, there's been absolutely no delay in facility construction. Since the parties had previously executed a letter of intent, the actual construction of the pipeline and compression has been proceeding on an expedited timeline. The pipe was ordered sometime ago and nearly 240,000 feet of 30 inch pipe is currently being received and prepared for construction at a local staging area.

Construction of the pipeline is expected to begin in September. We have a map in our slides and it shows that we anticipate that the just and aligned F (ph) segment will be in service by December 2005 and available to assist in serving system demand this winter. Compression has been ordered and is anticipated to be in service by March 2006.

Atmos will contribute its share of capital limited to 42.5 million which will be contributed as segments of the line are completed and placed in service. Of this amount about 4 million will be spent in 2005 and the remaining 38.5 million will be incurred in fiscal 2006. These expenditures become eligible for GRIP recovery in the calendar year they are spent. Incremental earnings through GRIP will be calculated the pipeline's collaborative (ph) return on total ratebase of 8.258%.

We continue to see robust demand for system capacity associated with new gas production being developed near our system, primarily in the Barnett Shale area around Fort Worth and the Bossier Sands area in East Texas. As a result we are also witnessing a healthy expansion in transportation margins. Creating increased capacity allows us to secure new supplies that are available to serve our utility customer needs and create new margins by moving gas to third party customers.

On May 17th we announced an agreement with Enbridge Energy Partners to transport up to 100 million cubic feet per day beginning in April 2006. To increase available capacity to this premium market we will install compression equipment near Howard, Texas costing about $20 million. The compression has been ordered and is anticipated to be in service by April 2006. Also, we signed an agreement last month with a third party shipper to transport an additional 50 million cubic feet per day that will also utilize this compression.

Like the Energy Transfer transaction, these expenditures are GRIP eligible. For 2005 we expect to incur roughly 3 million and the remaining 17 million in fiscal 2006. These expenditures become eligible for GRIP recovery in the calendar year they are spent. We continue to be pleased with the developments associated with our intrastate pipeline as we serve the needs of our customers.

Turning back now to our financial results. Our consolidated operation and maintenance expense for the third quarter was 94 million, up 44 million from the prior year quarter and was 314 million for the nine months ended, up 147 million from the same period a year ago. What's significant here is the accelerated operational savings in fiscal 2005 of about $20 million pretax what we expected to realize in fiscal 2006 from our TXU Gas acquisition.

Although the provision for doubtful accounts increased by 8.9 million for the nine months ended June 30, including the incremental provision for our Mid-Tex Division, we've actually experienced bad debt expense that equates to one-half of 1% of residential and commercial revenues which is actually very good by industry standards.

Depreciation and amortization expense and taxes other than income taxes and interest charges for both the quarter and nine-month periods have increased primarily since adding the new Mid-Tex and Atmos Pipeline Texas divisions. Interest expense increased due to higher debt levels associated with that acquisition. Miscellaneous income for both periods is affected by the sale of our propane business and office building in 2004; offsetting this the current period benefited from increased interest income earned from higher cash balances as compared with prior year period.

Looking at our cash flow, we generated strong operating cash flow for the first nine months of 387 million, up 28 million from the prior year period. The Company had no short-term debt at June 30, 2005. The incremental changes in our cash flow primarily represent the effects of the TXU Gas acquisition. Results due to increased net income from our new Mid-Tex and Atmos Pipeline operations contributed about $60 million.

We had favorable timing of our accounts payable, about a $32 million increase in cash. And a combination of things that provided more effective management of our working capital which was partially offset by higher volumes of natural gas held in inventory and a 10% higher utility average cost of gas, the timing of when we can include the recovery of gas costs in our rates and overall lower than expected utility sales volumes due to the warmer weather.

I'll spend a few minutes now talking about our capital expenditures which for the first nine months were 227 million compared to 130 million in the same period a year ago. The increase primarily reflects spending at Mid-Tex and at Atmos Pipeline Texas of about 94 million. We continue to pay close attention to our capital spending, not just in the aggregate, but distinguishing between growth capital and maintenance capital. Our objective is to limit our nongrowth capital spending to the level of depreciation expense that we recover in rates and in jurisdictions where we experience more timely recovery which is primarily Texas, Louisiana and Mississippi. For fiscal 2005 we are projecting total capital expenditures between 335 million to 345 million.

Now turning to guidance for the remainder of the fiscal year -- as you can imagine, with a sizeable acquisition like TXU Gas it's been a little challenging to develop a budget with full precision for the first year. After operating these assets for a full nine months and with some in-depth analysis of our consolidated operation we have isolated 20 million pretax and operating synergies from the acquisition which, as we've said, we originally anticipated to realize next year.

As a result of this acceleration of cost savings as well as cost containment across the enterprise, which has helped us to offset the effects of warm weather, we are comfortable with the middle of the previously announced range of $1.65 to $1.75. We are diligently working on our 2006 budget and anticipate sharing our 2006 guidance with you in our next earnings release in November. With that, once again here's Bob.

Thanks, Pat. I want to make a few closing comments and then we'll be more than happy to take any questions that you all may have. I mentioned earlier rate design and we have stated our goal and our focus is to increase our earnings at a rate of 4% to 6% a year. And in order to do that we've got to do things which take out the impact of weather, declining use and energy conservation and in the long run decouples the recovery of our improved margins from our customer usage.

I want to mention that we've made great progress over the last five or six years. We now have weather normalization in Kentucky, Kansas, Mississippi, Georgia, Tennessee, Virginia and West Texas. We've yet to get weather normalization in Louisiana or decoupling and with our new Mid-Tex Division. Of course in Colorado we don't need it because our earnings have been very good in that state. Which would mean if we can achieve this goal over time we would really have some type of mitigating rate provision in effect for all of our states except the three smallest which would be less than 100,000 customers total.

We do have some rate activity that we are moving along which is all intended to try to accomplish the goal of decoupling and/or mitigating. In May we made a margin decoupling filing in Louisiana to address weather conservation and bad debt expense and we're still moving that case forward and awaiting some formal data requests. In May we also filed our first rate increase in Georgia in nine years and we asked the Georgia PSC to increase our revenues by $4 million which equates to a 5% increase. And we expect staff testimony will be filed in the next couple weeks and then our goal is to put our new rates into effect in November of 2005.

In May we also informally proposed to the staff of the Mississippi Public Service Commission an annual stable rate plan versus the biannual filing that we're currently utilizing. And among other things we discussed, the sharing of earnings above an allowed ROE level, and also further stabilization of margins. And we continue to work with staff to reach an agreement and redesign rates prior to September 2005.

In Texas, as you may remember, Texas passed legislation last year which basically is called GRIP or it stands for gas reliability infrastructure and this allows us to, with our capital expenditures, not have to suffer the lag that we would otherwise suffer in waiting to file normal rate cases. So GRIP allows you to make filings for the capital expenditures you've made previously. In December of 2004 we made two GRIP filings for capital expenditures made in 2003 for the acquired TXU Gas properties. Atmos Pipeline Texas filed a 1.8 million of additional revenue and the Commission approved this filing in March of 2005. And this revenue is being recovered through a monthly customer charged since April of 2005.

Mid-Tex Division filed a $6.8 million filing for additional revenue and we expect the cities to take final action on this by the end of August and we will begin to recover these costs through a monthly customer charge beginning in the first quarter of 2006. We plan to file the second GRIP filing for 2004 capital expenditures for both Mid-Tex and the Atmos Pipeline in September and this filing will be in the $8 to $10 million range. So all of these filings will help our revenue as we move forward.

In Texas we are also wrapping up a standard gas cost recovery prudence review with the Texas Railroad Commission and these involve purchases over $2.2 billion made by the Mid-Tex Division from November 2000 through October of 2003 and briefing will be taking place in the latter part of August on this case. We've also filed an appeal on the Mid-Tex Division from an order that came out in May of 2004 in which poly -- one pipe replacement was originally disallowed by the Railroad Commission and so this case has been assigned to a judge and a briefing schedule has been postponed, but we'll move forward in the months to come.

In closing we remain very bullish about the acquisition of TXU Gas. All of you know that this was by far the largest acquisition we have ever done, but in fact it has had the smallest amount of integration issues involved with it. And I attribute that as much as anything to the tremendous attitude of the employees who came over with TXU Gas. From a pure business standpoint we now have a wonderful mix of assets.

We have an intrastate pipeline that is doing extremely well and has certainly been able to access a number of commercial opportunities in the less than year period that we've owned them. We've got great growth potential on our distribution properties of TXU Gas of 30 to 35 additional customers a year. We have tremendous performance in our marketing area of our Company that JD Woodward leads. And we also in our Atmos or what we call our Atmos Six (ph) where were the divisions besides TXU Gas -- we're working hard on rate design and their performance continues to rise as time moves on.

So as I mentioned earlier, our focus and our commitment is to grow our earnings 4% to 6% a year on average. To utilize this great mix of assets to continue to the make good investments that will give us great returns and also continue to pay down debt over time to get our capital structure back to where we want it in the 50% to 55%. With this earnings growth coupled with our dividend yield of almost 5% we continue to enhance value for our shareholders and be a company that performs very consistently and very predictably. So with that, I will turn it back to our operator and we will be glad to field any questions.

(OPERATOR INSTRUCTIONS). Gordon Howald. Please state your company name followed by your question.

Yes, it's Natexis Bleichroeder. Bob, thanks for the review of GRIP. That answered one of my questions; that was helpful. A little curious about the debt buyback. Maybe you could talk a little about how focused you are on increasing your credit rating if that is what prompted that? Are there more opportunities in the future? And if you could give us any color on what body language you're getting from the rating agencies at this point, where would you like to be in terms of your credit rating, things along those lines?

I will let Pat field that question, and Laurie may want to comment on it as well.

Sure, Gordon, that's a great question. The thing that was very gratifying to us coming out of a warm winter, it was 20% warmer here in Texas and 22% warmer in Louisiana, but with a good base charge here, our operating cash flow was stronger than you might imagine, and that's continued on through the summer months. So we found ourselves with a significant amount of cash on the balance sheet at the end of last quarter, and we have some legacy mortgage bonds that came to us with the acquisition of United Cities back in 1997 that had some modestly restricted covenants and some high nominal interest rates, and we decided that a good use of cash would be to retire that debt. It's going to save us a little over $5 million of interest expense next year. I think it was indeed a signal to the rating agencies that we're serious about our commitment to reduce our leverage.

It's going to be a balancing act. We've got some significant funding to do for these growth opportunities, at Pipeline and Storage and at Mid-Tex, and we certainly don't want to starve those. But at the same time, we do want to make progress. The next opportunity for us to retire some debt will be when the shortest maturity of the debt, that 1.4 billion of debt that we issued last year. There's a piece -- Laurie, I believe it's three years -- and at that point we'd have an opportunity to pay down some of that debt assuming our cash flow continues to be strong.

So we are in pretty frequent touch with the rating agencies and we've talked about the different reactions that we got from the three agencies when we announced the acquisition. And I think it was just incumbent on us to do what we said we were going to do to get these operating synergies to begin to reduce debt. And we look forward to a meeting with the agencies and updating them in a -- Laurie, I guess we don't actually have dates set -- but it will be this fall. So I think that will be an opportunity, particularly with Moody's, to do what they've asked which is kind of a post-mortem on the acquisition and help them to understand where maybe they might have been a little conservative in their assumptions.

But I think to answer your question, BBB flat to BBB+ is probably the sweet spot for us in terms of our weighted average cost of capital. That's down from A- ratings that we had before the acquisition. But I would just say that even then our debt traded in the aftermarket as kind of a strong BBB. So I think that that's an area that we'd be comfortable with going forward.

Yes, I don't think anyone can argue with the success you've had. Wonderful, thank you very much. I appreciate it.

Steve Brontos (ph).

Talon Capital. Congrats on a good quarter. I had a couple questions for you. One was on the cost savings that you've already achieved that you kind of pulled into '05 from '04, that was 20 million. What do you see above and beyond that for '06 and going forward in terms of cost savings? I guess the outsourcing arrangement goes away next year, right?

It does. I think, Steve, that at this point in time -- and we're continuing to study this -- we're in the midst of doing our 2006 budget. That's something that we'll take to our board at our September work session for approval. But it would appear to us that -- we talked before about operating synergies on the order of 15 to 20 million and that's really what we'd achieved at this point. I would say from the further in sourcing of the revenue cycle piece from Cap Gemini as well as in sourcing meter reading from Encore, that there aren't really significant savings associated with that. It looks like our cost of doing that would be kind of comparable for that piece of the outsourced business.

So I would say that at this point I think we've realized the substantial operating synergies. Now that doesn't mean that we're not going to continue to chip away. For example, we're in the process of putting Mid-Tex on our outsourced inventory management arrangement. And so there will be things like that that will give us some incremental savings over time but not of the same magnitude.

Okay. On the storage trading margins, is it fair to say -- it looked like there was an $8.4 million loss running through your numbers year-to-date which is I guess about $0.06. But that when you think about '06 that loss will not be there for '06. In addition you'll realize that $27 million or so of a margin over three fiscal years. So when we think about what the numbers might look like for '06 we can just kind of take that 8.4 which will go away, then you'll have some additional earnings on top of that as you realize those margins. Is that right?

I'll ask Rick Alford to address that.

Basically that is true. That's the way the mark to market works. At sometime in the future -- unfortunately we can't predict when that will be -- that $8.4 million negative mark that we have on the balance sheet at 6-30 will turn around at whatever point the market -- or the spread moves back in the direction for us to bring it back into income. The majority of that embedded value or economic value is scheduled currently on our plan to bring that back probably in the second quarter of '06 and then there's a tranche of it that moves over into '07. But basically, yes, your understanding is correct.

So that you've flowed that 8.4 million of losses -- you flowed it in this year's P&L and that you expect to realize it when you sell the gas out of storage which is going to be sometime in '06 and maybe a little in '07?

Well, just as a technical response to that, we will recognize that $8.4 million coming back in the income and the spreads compress. Now the part that we'll realize in cash will be the additional $18.1 million of embedded or economic value that we have which was a result of our weighted average cost of gas that we have in inventory compared to our weighted average sales price that we have locked in with our futures transactions.

So you won't ever realize the additional $18 million in earnings, that will just be a cash item?

We will recognize it both in earnings and in cash.

Lastly, on then on the project side, I know the Transfer partners and the Enbridge project is about 60 -- a little over 60 million of total capital need, most of that I guess will come in '06. And you said it's all GRIP compliant.

Yes.

So when you think about what the earnings impact might be -- I mean absent knowing what the terms of the contracts are and how lucrative that might be, but if we were just to apply a typical weighted average cost of capital from a regulatory perspective against those capital expenditures, that's the right place to start in terms of the earnings impact?

I think that's right. There are two components of earnings from that; one would be the regulated rate of return on the investment and then the second would be the commercial return from the shippers. But, yes, I think that would be a good place to start.

Okay. Thank you.

Paul Patterson.

Glenrock Associates. Just to follow up on that slide 51. Is that basically a nonqualifying hedge -- that reported GAAP value, the 8.4 million negative mark to market?

No, that is not a nonqualifying hedge. Those are fair value hedges that we have on against our storage book. But the impact that we saw from the mark to market was that these spreads expanded from what we had on the books originally that caused -- because of FAS 133 that caused a mark to market loss. To be recognized in the income statement and put on the balance sheet, but it's definitely a timing item, non-cash timing item.

Okay. It says here realizing economic value is highly dependent on the ability to execute. You made it sound like you guys have locked this stuff in from -- with respect to hedging and what have you. What exactly do you guys mean by the ability to execute? What exactly are the risks associated with that? And sort of as a wider question, how comfortable do you feel with the current mix of utility/non-utility in terms of operating income and how it might be going forward?

I'll let Rick respond to the first part. JD Woodward is here. Let me just mention the mix of assets. The intrastate pipeline is a regulated pipeline per se. Our real mix of assets if you want to look at it from a regulated/non-regulated standpoint is almost 90% regulated. There are commercial activities on that pipeline that we're able to take advantage of, so we kind of get the best of both worlds. But our mix traditionally has been about -- 75% of our income has come from the regulated segment of our business, about 25% from the non-regulated segment. And we really our basic business is distribution, pipeline and storage and market.

So the distribution is regulated, the marketing is unregulated and in pipeline and storage we have both regulated and unregulated. As I said earlier, we have a good mix of assets and we feel good about the asset mix that we have (technical difficulty) environment. I'm going to let JD Woodward who runs our non-regulated business answer that first question.

For the most part on execution, Paul, what we try to do is layer in our financial hedges against our physical that match off our operational capabilities as well as our commercial obligations that we've made for our storage gas. You've got to remember, storage is dynamic, it's not a fixed moment in time. What I mean by that is the capture arbitrage values between the physical and the financials are in the daily market, buying and selling gas as well as buying and selling financials as well as you're looking at your intrinsic term structure which is your physical let's say summer to winter spreads.

And to the extent that the market tells us to keep our gas in the ground (indiscernible) to keep it in the ground, we're going to reset financials month-to-month. So when we say execution, what we're trying to cover the proposition of it that storage is very dynamic, it shrinks everyday. So the end result of what you're seeing here simply come through P&L, (inaudible) the change in value to the physical. The actual portfolio, changing the value of that from the prior quarter.

So how much of that $18.1 million is at risk I guess is what I'm trying to ask. I mean it sounds like from that little footnote that you guys are indicating there's some substantial risk associated with the actual realization of that. Can you quantify that? Is that the case? Am I understanding that correctly?

You can't quantify it, but (inaudible) is an estimation. It's what we typically do internally -- we haircut that by 25% versus what we think (inaudible).

Okay. So in other words that 18.1 million recognizes a 25% roughly speaking haircut?

Actually it does not recognize a 25% haircut. That is the calculation of the (indiscernible) versus loss. But internally, when we look at the future we haircut that by 25%, as JD says, but it's not in the 18.1 million (inaudible) the budget income. That's an attempt to be conservative.

And then just to follow-up on this economic -- the regulated versus non-regulated. You said historically that 75% is regulated, 25% is non-regulated and the assets are actually more like 90% regulated, etc. Not to get into the semantics here, but when we look at that 68/32% how much of that is coming from regulated activities versus non-regulated activities? If you could just clarify that in terms of what the mix has been in the last nine months.

Right. And really how you have to look at it -- you can look at it several ways. The intrastate pipeline is really the one that if you count that as regulated then I don't know what the calculation is. We could come up with it here.

Whatever you've got. I can get back to you guys on that. It's not imperative. Just the final thing I wanted to ask you guys about was conservation. Looking at the data that you guys supplied, it was hard for me to actually sort of pull out the impact of the acquisitions, etc. But what are you guys seeing in terms of conservation? You mentioned how you guys are going after the weather adjustment issue in terms of making sure that you're not tied to customer usage in terms of your earnings growth and what have you. But what about conservation and elasticity? Are you seeing any impact on that like we are hearing about others in the industry?

I think we definitely are in declining use per customer. That continues at about 1% per year as it has for the last 15 or 20 years in the marketplace due to equipment being much more efficient and due to houses being better insulated. The other thing that is happening to us because we've been so aggressive in our collection efforts, we see customers leave who don't always come back. So we have had certainly conservation and, as I say, declining use per customer in the marketplace.

We have not seen, on the other hand, a huge drop at all in our industrial market. I know some companies have talked about that, but we have not seen that ourselves. Although we, in most of our divisions, are not a heavily industrial company in terms of our customer base. That has not hurt us as much. But declining use continues to be certainly an issue for us and that's one of the reasons that we are being so focused on these rate design changes which will put -- give us more stability in our earnings and mitigate conservation, mitigate weather and mitigate other elements that cause our usage to be somewhat volatile.

And Paul, I have that breakdown for you of regulated and non-regulated for the nine months. In the regulated segment it would be our Atmos Six utilities, our new Mid-Tex division and our Atmos Pipeline Texas Division and that's 128 million or 84% of our total net income. And then the non-reg would be our natural gas marketing and our Atmos Pipeline and Storage Division and that's 24.5 million or 16% of the total.

That's very helpful. Just finally on the conservation, how much of an impact can you quantify what you actually have seen with respect to on the residential and commercial, what kind of decrease you've seen per usage?

I don't really think that we've seen a huge amount of decrease for usage with the higher prices that have been caused by those prices. Obviously customers are cognizant of higher prices just like they are at the gas pump. But we have not seen as much a change in behavior as one might imagine in the residential market.

Thank you very much.

(OPERATOR INSTRUCTIONS). Steven Strassberg.

Longbow Capital. I just have a question on slide number 40, and I apologize if you mentioned this earlier. You're showing for the pipeline and storage segment on the purchased gas cost a negative $1.7 million. Could you just discuss how that comes about?

Just one second, we're looking at the slide now.

Sure.

Just one second. We're just getting the slide here.

Steve, I think what that relates to is the fact that in that pipeline segment here in Texas we recover fees for lost and unaccounted for, for processing and transporting gas and in this three month period -- JD, do you want to elaborate on it?

(inaudible). The extension of -- well, let me back up. On the pipeline and storage business we retain gas to cover LNG, 1% on our pipeline system. When we are over retained we in effect have extra gas on our system and we (inaudible). And that 1.7 is the valuation -- the volume of gas that we have (inaudible) over and above our cost.

So what you're saying is you have -- for a variety of reasons, efficiency (ph) or whatnot -- you have excess gas that you retain, but you didn't sell this excess gas, you marked this gas to market and then it -- there was a gain on it and then it reduces your overall cost?

I think that's a fair way to characterize it, yes.

Okay. Thank you.

Reza Hatefi.

Zimmer Lucas Partners. I'm a little confused on the O&M shift I guess. During the analyst meeting you talked about reduction of about 20 to 25 million by bringing TXU onto your platform and then maybe getting some further O&M savings from Cap Gemini and so forth. So does that mean that basically you got the 20 to 25 from bringing TXU onto your platform but the Cap Gemini, etc., didn't work out as you had planned. I kind of got confused.

Not really. At the time that we announced the acquisition we talked about the fact that we had a one year outsourcing arrangement with Cap Gemini for things like call center and for the revenue cycle -- sending the bills to the customer and collecting the bills. And then we also had an arrangement with an affiliate at TXU called Encore -- they're an electric service provider -- to read our meters.

What we did, though, within this period is we accelerated a piece of this. We brought back in the call center as of April 1st. We stepped into Cap Gemini's lease at our Waco call center and hired a subset of the agents that Cap Gemini had hired and I think we talked on our last call that that helped us accelerate about 2 million of savings in the balance of this year and about 6 million on an annualized basis. That's an example of something that we were able to accelerate.

Also there were elements like we moved the Mid-Tex employees up here to a tower next to where our offices are located and we had lower rent expense -- we shut down basically their former Harwood (ph) complex, mothballed it. And so there were a lot of things kind of in and out like that that we were able to do more quickly. And then the remaining things that Cap Gemini is doing for us -- the billing of the customers, printing the bill, mailing the bill, collecting the money -- those are things that don't have substantial savings associated with them. Our cost of doing that is roughly equivalent with a new billing system that we're putting in. We've got some capital expenses that all increase our depreciation a little bit but they're just isn't as much room there we don't think for additional savings.

So this 20 to 25 million, that's a correct number, something like that?

It's 20 million year-to-date over and above what we budgeted. And Reza, you remember, that's in addition to the 25 million of reduced G&A that we achieved at the outset.

Okay, that was my question. That was due to the over allocation from the TXU parent?

Right. In total that's about 45 million year-to-date.

Okay, great. And what is your target -- what do you think your ending '05 debt ratio -- debt to cap ratio will be?

It's gone down modestly since we closed. And I would -- the thing about that though is that we're going to have more short-term debt, but the (multiple speakers) because we're buying gas to put gas in storage.

A little lower than what you're -- a little higher debt ratio than what you have at the end of this quarter?

Correct.

Great. Thank you very much.

Paul Patterson.

Could you remind us when you guys are going to expect to get into the 50% to 55% debt to cap ratio?

We've said three to five years and the reason for having a range is, as I mentioned earlier on the call, we don't want to starve these growth projects. And so really the balancing act for Laurie and I will be to figure out between operating cash flow and additional financing -- as we evaluate these projects what that best mix is. But I would just say that going back to 2000 our debt to cap was 62% and right before the TXU acquisition we had gotten that down to 48%. So that's kind of the history that we've had and you can kind of see that typical pattern with an acquisition. So I think three to five years is a realistic time frame.

You don't feel that you're ahead of schedule at all?

I think we are a little ahead of schedule. I think we've been pleasantly surprised at how strong the cash flow's been from Mid-Tex even with the very warm winter that we had.

Thanks a lot, guys.

Reza Hatefi.

I had a follow-up question. You guys had previously put out some slides in previous calls talking about potential revenue or rate increases in all your jurisdictions going forward. I was wondering, do you have an estimate for what your total '05 rate increases will be and then also for $0.06 do you have a rough number -- what you think could happen?

I think we've said 15 to 20 to 25 million is our run rate. Reza, we have filings we have to make each year in Louisiana and Mississippi under those rate stabilization clauses. We have our GRIP filings that we have to make in Texas. We now have a filing, as I mentioned earlier, in Georgia. We're looking at several other filings in some of our smaller states.

I honestly think when this franchise is working well and the way we want it to work is that we're able to which 12 states in which we do business we're able to plan our spending strategy in order to coordinate our rate filings. That really ought to give us an advantage over time an we'll continue to work on rate design which is just -- in some cases just as important to us as our rate filings. I really think in the 15 to 25 million range is probably on average -- I'm not saying -- there could be a year where that doesn't happen, but that's sort of been our run rate as we go forward. Particularly since when you consider 75% of our distribution assets are in Texas, Louisiana and Mississippi, so those states obviously are very big ones for us.

Reza, we're filing our 10-Q later today and you'll see beginning on page 63 there our year-to-date rate making activity and it's broken down by Mississippi, Mid-Tex, Atmos Pipeline Texas, Louisiana and mid states. So you can see a lot we've filed for and what we've received this year.

Great, thank you very much.

There are no further questions at this time. Please continue with any additional comments.

We just want to thank you all for being here.

Appreciate all your questions and look forward to talking with you next quarter.

Thank you.