埃特莫斯能源 (ATO) 2006 Q3 法說會逐字稿

Good morning ladies and gentlemen and welcome to the Atmos Energy third-quarter earnings conference call. At this is this time all participants in a listen-only mode. Following today's presentation instructions will be given for the question and answer session. (Operator Instructions). As a reminder, this conference is being recorded today, Thursday, August 10 of 2006. I would now like to turn the conference over to Susan Giles, Vice President, Investor Relations. Please go ahead, ma'am.

Good morning everyone and 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 have placed slides on our website that summarize our financial results. We will not review those in detail, but we will take questions at the end of our prepared remarks. If you would like to access the web cast and slides, please visit our web site at AtmosEnergy.com and click on the conference call link. In addition, we filed the Company's form 10-Q late yesterday. A copy of that can also be found on the investor relations home page of the web site.

With me today are Bob Best, Chairman, President CEO and Pat Reddy, Senior Vice President and CFO. There are also members of our leadership team here to assist with questions as needed. Let me remind you that 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. And [forward-looking] statements are intended to fall within the Safe Harbor rules of the Private Securities Litigation Reform Act of 1995. With that, I will turn the call over to Bob.

Thank you, Susan, and good morning everyone and we appreciate you joining us today and we appreciate your interest in Atmos Energy. As Susan mentioned, Pat Reddy, Chief Financial Officer, will review the financial results in just a moment, but before he does I want to talk about our business, some of our recent accomplishments in the rate area and regulatory area and how strongly we feel that our company Atmos Energy is well positioned going forward.

The core operations of our business are performing very well. At the utility, we have been executing our rate strategy and we've been very resolute as we talked to all of you about stabilizing our utility earnings from the effects of conservation, [declining] use and abnormally warm weather. And I will talk about these matters in detail in just a couple of minutes.

In the non-utility part of our business, we continue to take advantage of the volatility in the marketplace. This quarter, we experienced a non-cash unrealized loss only because -- and I want to emphasize -- only because of the accounting treatment required on our marketing and storage positions. This is only temporary and I know all of you understand that this money will come back at a future date to us.

The Pipeline and Storage segment continues to execute as we have planned. All of the four projects that we announced last year are complete and have been placed in service on the intrastate pipeline in Texas which we obtained as part of the TXU Gas acquisition. Our marketing segment continues to add customers and most of this business or all of this business is fee-based business and it continues to see very strong margins in the marketplace. We have remained very bullish as we have from the outset about the TXU Gas acquisition and its potential, especially now with the rate changes that we have been able to effectuate in the Mid-Tex division.

I want to now talk about the positive regulatory results that we would like to share with you. First of all, we received critical rate design changes in both Louisiana and the Mid-Tex Division. WNA -- weather normalization -- will be effective in the Mid-Tex Division beginning on October 1 and a modified weather normalization clause which provides for partial decoupling goes into effect this December 1 in our Louisiana division. With these two changes -- and you realize that these two companies approximate over 60% of our customer base in the utility -- approximately 90% of our margins will be decoupled from weather for this coming season, and that's something that we been working on in a very resolute way, well, really since we acquired TXU Gas.

We also filed a rate case in the Mid-Tex Division in May and we requested an increase in incremental annual revenues of approximately $60 million, and rate design changes that include margin decoupling, not only from weather as I mentioned, but also from customer conservation and the recovery of the gas portion -- gas costs portion of our bad debt expense.

In July, the Railroad Commission of Texas approved the use of WNA on an interim basis and we also reached agreement with all parties that they would support WNA on a permanent basis as part of our rate case. The interim WNA uses 30 years of weather history while the permanent WNA will allow the parties to discuss the appropriate method of weather data to use in calculating normal weather going forward. We expect this rate case to be finally decided in February of 2007.

In Louisiana, we filed over a year ago to request approval of a decoupling mechanism to stabilize margins, but this filing was delayed after the hurricanes hit the state last August and September. This May, the Louisiana Public Service Commission consolidated our outstanding dockets and settled on several rate issues. They approved a modified weather normalization clause that over a three-year period allows us to recover our margins and O&M expenses, regardless of weather or declining customer use. Normal weather is defined as being an eight-year period instead of the historical -year period. They renewed the Rate Stabilization Clause with provisions to reduce regulatory lag by allowing us to true up on an annual basis. They also allowed Atmos to recognize into income about $6 million of utility margin that had previously been deferred. This income was associated with the 2003 rate stabilization filing. We expect to make a rate stabilization filing for the LGS service area in August with an expected effective date of August 12. This filing will allow us to reset our customer count and also will allow us to begin to recoup some of the expenses related to last year's hurricane.

As I said, with these positive results in Texas and Louisiana, our utility margins should be about 90% -- in excess of 90% -- insulated from weather in the upcoming winter, a key accomplishment that will help us unlock the full potential of our utility franchise.

Now I'm going to turn the call over to Pat for his review of our financial results in more detail and then I will be back for some summary remarks and to open the floor up for questions at that point. So Pat, I will turn over to you.

Thank you, Bob and good morning. I'm going to speak to the more significant items in the quarter and for our year-to-date period and then discuss our outlook for the remainder of our fiscal year.

As we said in our earnings release, for the third quarter of our fiscal 2006, the Company experienced a net loss of $18 million, or $0.22 per share compared with income of 4.5 million, or $0.06 per diluted share in the same period a year ago. For the nine months ended June 30, our consolidated net income was about 142 million, or $1.75 per diluted share compared with over 152 million, or $1.94 per diluted share a year ago. The three biggest drivers of our earnings results this quarter and year to date continue to be warmer weather at the utility, unrealized noncash mark-to-market losses at the marketing business and increased operations and maintenance expenses across the enterprise.

Utility gross profit declined about $5 million in the current quarter but rose over $10 million in the current nine-month period. Utility gross profit was most impacted by the effects of warmer than normal weather. Quarter-over-quarter, weather was 29% warmer than the same period last year and accounts for 16 million of the decrease in utility gross profit. Year-over-year, weather was 3% warmer than the same period which negatively affected gross profit by about $22 million. Year-to-date, weather was 13% warmer than normal as adjusted for our areas with weather normalized rates and negatively affected gross profit at the utility by about $47 million in the current nine-month period. This is important because our budgeted earnings for the full fiscal year reflect 30-year normal weather as do our rates in most of our jurisdictions.

The greatest impact of weather on our financial results was experienced in the two largest jurisdictions which did not yet have weather normalized provisions in their rate structures for this fiscal year, our Mid-Tex and Louisiana divisions. Combined, these two jurisdictions have about 1.8 million customers or 56% of our total customer base. For the year-to-date, warmer than normal weather in these two divisions alone accounted for almost 33 million of the reduction in utility gross profits, so you can understand the urgency behind our securing WNA in these two divisions for our next heating season. You can look at our slide deck and slides 8 and 9 show the impact of weather normalization by utility division.

On a positive note, year-to-date we experienced about 8 million in increased margins from rate adjustments associated with the 2004 and 2005 filings in Texas to adjust our rate base for capital expenditures made during those years. That is our so-called [GRIP] program in Texas. In return quarter and year-to-date, we also recognized about 6 million of utility margin that had previously been deferred. This was associated with the 2003 rate stabilization filing in Louisiana which was settled this past May. Offsetting these positive factors was the negative impact of almost $5 million from hurricane Katrina year-over-year. As we previously disclosed, we anticipated the reduction in utility gross profit for the full fiscal year of between 8 and 10 million with a negative impact of hurricane Katrina. A little later in the call, Bob is going to talk to you about the filing that we're going to be making this month that will allow us to reset our customer count for rate purposes in Louisiana.

Our natural gas marketing gross profit for this quarter was a loss of almost $1 million, down substantially from gross profit of about 10 million a year ago. For the current nine-month period, gas marketing gross profit reached $69 million compared to 48 million a year ago. The real driver in the $11 million decrease quarter over quarter lies with the mark-to-market impact on our margins. For the current quarter, the storage and marketing margins included a negative mark-to-market impact of about $21 million which resulted from the change in value since March 31, 2006. In the same period last year, the storage and marketing margin included less than 200,000 of non-cash mark-to-market losses. The resulted in combined negative swing of roughly $21 million quarter-over-quarter in unrealized non-cash market mark-to-market impact. However, operationally, we realized an increase of over 9 million in our storage margins quarter-over-quarter due to favorable arbitrage spread opportunities compared to the same quarter last year. Realized marketing margins were virtually flat quarter-over-quarter.

Year-to-date, the storage and marketing margins of about 69 million include a $38 million negative mark-to-market impact which resulted from the change in value since September 30, 2005. In the same period last year, our storage and marketing margin included about 10 million of negative mark-to-market impact resulting in an increase year-over-year in unrealized non-cash mark-to-market losses of about $28 million. But, again, operationally, we experienced an increase in our realized storage and marketing margins of over $49 million year-over-year. This was largely due to our ability to capture favorable arbitrage spreads in our storage operations as a result of unprecedented market volatility during the period primarily due to the aftermath and the effects of hurricanes Katrina and Rita, and as a result of a 28 Bcf increase in our marketing sales volumes and an increase in our marketing margin period over period, again, due to unprecedented market volatility due to the hurricanes.

As we've said before, with the incremental storage acquired in the third quarter of fiscal 2005, we are exposed to increased volatility in our margins. We had almost 5 Bcf of incremental physical storage at the end of June 2006 compared to June 2005 which further contributed to the mark-to-market losses this year over last year.

Also, as you know, Atmos Energy marketing maintains a flat trading book and avoids mismatches between the volume of gas in storage and the number of associated financial hedges. We also do not engage in speculative trading and AEM uses financial hedges to lock in and economic gross profit margin at the time it enters into a storage transaction. Therefore, the mark in any quarter close reflects a snapshot of liquidation value, but when our gas is cycled from storage and the financial hedges are settled as plans, these marks are eliminated. (indiscernible) for financial reporting purposes, our storage book can add significant unrealized gains or losses to our storage margins. The economic gross profit we have captured and the original transaction will remain essentially unchanged. We recently placed a presentation on the investor relations section of our web site that provides an explanation of the accounting for our storage operations for those of you that would a little additional background.

The embedded value of our storage book is quantified in our 10-Qs and also in the appendix to the slide presentation on our website. It 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 a reporting period. Economic value is equal to the difference between our weighted average sales price and our weighted average cost of gas. At the end of June, the economic value of volumes held in storage was about $28 million (technical difficulty) recorded (technical difficulty) in the trading margin was an unrealized loss of almost 58 million, yielding an increase in future gross profit of about $86 million. Based on the current setup of our storage book and the assumptions at the end of the current period, recognition of the 28 million of economic value and realized trading margin which straddled fiscal 2006 and fiscal 2007 with the bulk of it being realized by March of 2007. The timing and actuality of the unwinding of the negative 58 million of unrealized loss currently recorded on the books is dependent on the embedded spreads and market spreads. However, we have seen market spreads tighten in July. At the end of June, market spreads were roughly $4.50, and by market spread, we mean the difference between cash prices and future prices. At the end of July, we estimate the market spreads to be into $3 to $3.50 range. This tightening should allow us to reverse in the month of July a substantial portion of the 58 million negative mark-to-market balance that was on our books at the end of June. Also, our current withdrawal schedule (indiscernible) to reduce our storage balance by about 6 Bcf by the end of September which should also reduce volatility at the end of our fiscal year. Of course the withdrawal schedule subject to revision based on market conditions. Although we anticipate being able to reverse a portion of our mark-to-market losses in the fourth quarter, the mark-to-market balance at the end of September will depend on physical and forward prices and storage volumes at that time.

Now let me turn to our Pipeline and Storage operation. Gross profit was basically flat quarter-over-quarter. For the nine months ended, Pipeline and Storage gross profit increased about $7 million. The improvement in the current nine-month period was largely due to higher transportation and related service margins on the Atmos Pipeline Texas Systems and favorable arbitrage spread in the Atmos Pipeline and Storage asset management contract.

At this point, I will provide you with a brief update on some of the pipeline projects that we've talked about in prior quarters. The Northside Loop project that we embarked on with our partner Energy Transfer Partners is now complete and was fully placed into service this past May. As of June 30th, we've spent about $46 million for this project and we expect to spend an additional $5 million in the remainder of fiscal 2006. This project involved a joint construction, ownership and operation of a 45-mile 30 inch natural gas pipeline in the high-growth area just north of our DFW Metroplex. Adding this pipeline looping solves deliverability issues for our utility and creates commercial opportunities for our pipeline.

These expenditures are GRIP eligible. They become eligible for GRIP recovery in the calendar year in which this capital is placed in service. Recovery through GRIP will give the pipelines a [loud] rate of return on total rate base of 8.258%. We continue to see robust demand for system capacity associated with new production being developed near our system. As a result, we are witnessing healthy expansion and transportation margin. Creating increased capacity allows us to secure new supplies that are available to serve our utility customer needs and create new margins by moving the gas to third-party customers. We have entered into agreements to transport natural gas through our Texas Intrastate Pipeline with producers such as Enbridge, Devon and others. To handle the increased volumes for these projects, we installed compression equipment and other pipeline infrastructure. We have spent approximately $30 million in fiscal 2006 for these projects which were placed in service in June. These expenditures are also GRIP eligible.

In May, we announced plans to construct a 20-inch 65-five mile natural gas gathering system in eastern Kentucky known as the Straight Creek Gathering Project. Although this is our entry into the midstream business, it really isn't much of a step-out for us and it comes at the urging of several of the local producers in that area. It will initially be capable of moving up to 100,000 Mmcf per day of gas from local producers and it's expected to release severe pipeline constraints and accommodates the rapidly expanding production in the Big Sandy region. More than a dozen producers have signed memoranda of understanding to commit their gas volumes to the new system and to enter into agreements on commercial reasonable terms. The (indiscernible) purchase agreements are now being drafted for presentation to each producer who has executed a memorandum of understanding.

The project is pending all required regulatory approvals and is contingent upon receiving an exemption from regulatory oversight by the Federal Energy Regulatory Commission. We expect the FERC's decision sometime in September at the earliest. Upon receiving FERC approval, construction is expected to begin in the first half of fiscal 2007 and operations to begin in fiscal 2008. The project is expected to cost between 75 million and 80 million and to provide after-tax returns in excess of 15%.

Now back to our financial results. As anticipated, our consolidated operation and maintenance expenses for the third quarter increased 13 million and almost 20 million for the current nine months. The rise in O&M for both the quarter and the nine-month period is primarily due to increases in employee costs as a result of adding additional headcount to support our Mid-Tex operations and increase benefits costs resulting primarily from changes in the pensions used to determine fiscal 2006 costs. The provision for doubtful accounts for the current nine-month period increased by $4 million. Higher natural gas prices and gas price volatility remained a major challenge. Our current run rate on bad debt expense equates to about one-half of 1% of residential and commercial revenues. I would just say about our O&M expenses that while they were up year-over-year, we are slightly below budget for year-to-date.

Looking at cash flow for the first nine months of our fiscal year, we generated operating cash of about 223 million compared to operating cash of 387 million in the same period a year ago. The $164 million decline from last year reflects the adverse impact of high natural gas costs on our working capital management efforts. We are, however, beginning to see this impact turn the corner. Lower accounts receivable and natural gas inventories improved operating cash flow by almost 80 million as compared to the prior year and favorable movements in the market indices used to value our marketing segment's assets and liabilities have reduced that segment cash margin deposit requirements which favorably affected operating cash flow by 45 million year-over-year. These improvements in cash flow were offset by about 252 million caused by unfavorable timing of payables and other accrued liabilities and roughly 54 million in deferred gas costs due to the timing of collecting this cost from consumers [through rates].

Our capital expenditures for the first nine months were 323 million, compared to about 227 million in the same period a year ago, an increase of about $96 million. The increase primarily reflects spending associated with our Northside Loop Pipeline Project of about 46 million and the other pipeline expansion projects where we invested about 32 million which were completed during the fiscal 2006 third quarter. For fiscal 2006, we remained on-track for projected capital expenditures to run between 400 and 415 million. Of that, we expect between 200 and 228 million to be maintenance capital and between 180 and 187 million to be invested in growth projects.

Turning now to our earnings guidance and outlook for the remainder fiscal 2006, with the heating season behind us and knowing the actual weather impact on our operations, we nevertheless believe that Atmos Energy should achieve a level of earnings this fiscal year at the lower end of the previously announced range of $1.80 to $1.90 per diluted share. And as I mentioned earlier, it's important to note that we assume 30-year normal weather in our budget process and resulting guidance for the year because that's the standard used for regulatory purposes in [steadying] rates. Although the impact of warmer than normal weather at our utility was a challenge again this year, we believe it can be substantially offset by the performance in our nonutility businesses for the remainder of the year. The volatility that we continue to see in natural gas prices can provide positive opportunities for our marketing operations. However, as we just discussed, that also means (technical difficulty) of unrealized mark-to-market losses (technical difficulty) fiscal year. We're currently scrubbing our fiscal (technical difficulty) budget (technical difficulty) our 2007 guidance with you in our next earnings release in November. Now once again here is Bob.

Thanks, Pat, and I would like to make a few more comments and then we will open the floor up for questions. I'd just like to say, listening to Pat's report, we have delivered very solid results year-to-date and we have really overcome a very warm heating season and also the effects of hurricane Katrina in Louisiana. I think the takeaway from this call for us is that we have been able to receive critical rate design changes in both Louisiana and Mid-Tex Division that we promised many of you that we would obtain. These rate changes protect our utility margin going forward, and as we stated earlier, almost 90% of our margin will be insulated from unseasonable weather patterns in the upcoming heating season. WNA will be effective in Mid-Tex on October 1 and a modified WNA, which provides for partial decoupling, goes into effect this December 1 in Louisiana.

Looking forward, we expect to make a filing in Louisiana later this month to reset our customer count which was lowered because of hurricane Katrina and to recoup some of the expenses that we incurred last year which were related to the hurricane. We will continue to pursue our rate case in the Mid-Tex Division, our $51 million rate case filing. We believe that should be resolved in February of next year.

Additionally in Texas as we've described before, we have the gas reliability infrastructure program in place which continues to work well. The so-called GRIP program in Texas has allowed us to increase our rate base by almost $200 million dollars and earn our allowed return on that investment of about 35 million, our capital expenditures since 2003. The GRIP legislation allows us to refresh our rates annually so that we can begin to earn a return on those incremental investments and reduce the lag between the time we make the investment and our opportunity to earn on it.

So we're not finished yet in our regulatory efforts. We will continue to see great design changes that decouple the recovery of our proved margin from customer usage due to weather, declining use and energy conservation. We also will continue to seek to recover the gas cost portion of our bad debt expense and we will continue to invest in jurisdictions that provide quick and adequate returns on our investments.

At Atmos, our stated goal is in our rate strategies to earn our allowed rate of return in all 12 of our jurisdictions every year. As you have heard Pat describe, our marketing business continues to execute on its strategy and take advantage of volatility in the gas market. They continue to add new customers and continue to increase their margins. Our Pipeline business continues to provide superior returns on its projects. The Intrastate Pipeline has been a valuable asset to us, especially with the tremendous amount of drilling that continues unabated and actually continues to increase in the Barnett Shale in the Fort Worth area.

We're thankful for those of you who have supported us during this period as we've worked with regulators in Texas and Louisiana to secure these very significant and important rate design changes going forward.

I also want to mention that on this conference call that Earl Fischer will be retiring on October 1. Earl has led our utility operations for the last six years and has been part of our company for over 44 years and he has just done a remarkable job in helping us grow our earnings and to be able to make the progress we have in our rate and regulatory matters over that time. Kim Cocklin is the newest member of our leadership team. Kim will be taking over for Earl on October 1 and be over all of our utility operations. Many of you know Kim. He came from Piedmont Natural Gas and I know he will do a great job as we continue to pursue our regulatory strategy in order to increase our earnings.

You'll also recall that Mark Johnson was named Senior Vice President over Nonutility Operations this past April when J.D. Woodward retired. And Mark is also with us on the call this morning and is doing an outstanding job in running the Nonutility operations. Mark had been part of J.D.'s team since 1992 and both of these leadership changes have and are resulting in a very smooth transition and one in which we anticipated and spent a lot of time planning for.

We have a strong mix of assets, which we've talked about on each of our calls, but [of] our Distribution business, which is really the underpinning to our Company, and then we have our Pipeline and Storage business and our Marketing business. So we have three ways to be successful and to make money and to grow our earnings.

From a financial standpoint, we are encouraged about continuing to grow our consolidated earnings at our stated goal of 4% to 6% a year on average, and this will be our sixth consecutive year of meeting those targets and increasing our earnings per share. Our recent rate design changes will allow us even more predictable and stable earnings as we go forward.

Additionally, our Board of Directors yesterday declared our 91st consecutive cash dividend, making our dividend for fiscal 2006 $1.26 per share. With this earnings growth, coupled with our dividend yield of almost 5%, we continue to enhance value to our shareholders and run our company very well. This concludes our prepared remarks and we will now be happy to entertain any questions that you may have.

(Operator Instructions). Lance [Edis], Calyon Securities.

Hi. Just a couple of quick questions. One, on the Texas type GRIP filings, it seems like that's kind of like a performance-based rate making another version of that. So my question is, if it allows you to earn higher ROEs in return for lowering fuel costs to customers, does this upside go away after the 2009 Texas pipe rate case?

No, it doesn't. The GRIP legislation, which was passed in Texas, allows us to update our capital expenditures every year, but we earn the return that we are allowed on our rate base which is set in our -- the previous rate case. The only requirement that -- if you use GRIP, you have to file a rate case every five years. And of course, we've just filed one. So when we come out of this rate case in 2007, which we expect will be, and we mentioned February of 2007, we would not have to file another rate case for five years from that point.

So there won't be -- they won't go back in time on those and you think that this will just be an ongoing thing every five years you've got to come in?

Right, and that's on the distribution side now. Now the pipeline side we haven't filed a rate case, so we would have to come back I think in 2009.

Yes, that's what I'm looking at. So that's the same situation?

It's the same situation. If you use GRIP, you can update your capital, but you have to file a rate case every five years.

But what about the -- it seems like you're getting some excess allowed returns there for lowering customers' fuel costs.

No, we're really not. We're getting our return that we're allowed coming out of whatever the last rate case was. So we're not really getting any excess returns. It's really a matter of eliminating any significant lag in updating our rate base. So we're not investing capital and having to wait until we file the rate case, we're able to put it in our rate base fairly immediately.

Lance, our feel costs in Texas are reviewed in separate proceedings. We make annual filings and we have reviews every three years and that is an area where we're interested and migrating to a different kind of a program where we get preapproval really of our purchasing practices and don't have hindsight reviews. And we believe there could be some interest at the Commission in taking that up.

This is Craig from Calyon just chiming in for a quick clarification. On the extra returns we're talking about, aren't you allowed returns from commercial relationships that kind of give you extra total returns on the expansion CapEx in your pipeline division? And when you do go in for rate case in '09, wouldn't it be reasonable that would be evaluated in the returns that you are allowed?

The way we have organized our business is that the returns from the pipeline business are regulated. They do get reviewed every five years. The commercial transactions that we enter into with shippers are conducted by our marketing business. That is not a regulated business, and those our transactions where the marketing company basically acquires capacity on the Texas Pipeline and remarkets that capacity, for example on our Northside Loop. And so those revenues really are not part of the rate case.

Okay, maybe we could talk about it off-line. I guess I am a little confused on the relationships versus say what other companies have, like AGL between its marketing and trading unit and the pipeline or the utility assets.

Right, they have a slightly different model as we have discussed. We don't -- in asset management plans, we don't go in and propose to split savings going forward. What we do is we bid for capacity under PBRs or under asset management programs in our various states. And if we are the winning bidder, the customers get the benefit of the lowest rate and we keep whatever upside we can generate. It's just a different model, Craig.

I think Lance had a couple of very quick additional questions. Sorry for taking so long.

Just two quick questions. You said that you're going to an eight-year weather history versus a 30-year. Given that weather has been so poor for you guys, are you going to take a bit of a hit on that on the weather normalization as far as versus the 30-year which we sort of had been using as the weather normalized impact?

I don't think so, Lance, and specifically the eight years that Bob mentioned is in our Louisiana jurisdiction, and we just think that the last eight or 10 years is a much better reflection of the kind of weather that we have been having. And when you think about it, weather normalization just compares the current weather to some prior period, whether it be eight years or 30 years. And by using eight years, there will be less of an impact I think on customer bills because actual weather won't differ as much from the eight-year average as it would from the 30-year average. So it's really, at the end of that, we have a three-year period under this pilot program where we'll basically true up our margin and our O&M expenses. So in essence, we think about this full margin decoupling -- we get to take into account actual weather, actual customer count, actual expenses and actual throughput. So for us, the idea there really is to get all of our utility business units on that kind of a stable footing so that the cash flow and earnings each year will be predictable and transparent and not dependent on customer usage levels or weather.

And I assume the same applies for Mid-Tex? And also, you mentioned at the beginning of the call that you also want to get returns locked into the effects of conservation. Have you guys quantified the effects of conservation? I don't see anybody else that has done that. It would be interesting if you guys had done that.

For internal bridging purposes, we have looked at declining gas usage per customers. There's AGA data out there that shows on an industry-wide basis how usage has declined. But that's not something that we have talked about publicly.

Okay, thank you.

Josh Golden, JP Morgan Asset Management.

In prior conversations, there has been some talk about paying down the debt from the TXU Gas acquisition that happened about 1.5 years ago or so. I am curious to follow up on that. In addition, when is the last time that you have sat down with the rating agencies and spoke with them? And I'm just curious, given your CapEx expenditures and the acquisition of the TXU Gas, where stands now. What are the plans and how soon do you think you will pay down that to the targeted range set by management?

Scott, this is Pat, and one (technical difficulty) on that is, we talked about getting our debt to capital down to more traditional levels for a gas LDC as to say 50 to 55% in a three- to five-year time frame and the reason we talked about a range both of the percentage and time frame was we knew that it was going to take us some time to get more stable rate designs here in Texas. And we were gratified that we were able to do it this coming winter and that we don't have to wait to get through the rate case to do that. But the other thing I wanted to mention is that we're not really paying down long-term debt, we're reducing leverage the old-fashioned way by operational deleveraging, adding through retained earnings to our equity base and not taking on incremental long-term debt. And even with the warm winter, even with high gas prices and higher working capital commitment, we've been able to keep our debt to cap at a little under 60%. So we feel good going into this coming winter that with the improved rate designs in Louisiana and Texas, along with the better rate designs we already have in Mississippi, that for 75% of our customer base will have better and stronger cash flows regardless of the kind of winter weather that we have. And I will ask Laurie Sherwood, our Treasurer, to comment on recent discussions with the rating agencies. So I would just say as a general matter, we stay very close. We had a conference call with at least one of the agencies after we announced the fact that we got [EE&A] here in Texas. They were very interested in how that would work and what kind of difference it would make, but I'll ask Laurie to elaborate.

Thanks very much, Pat. We do as Pat said keep in constant touch with the rating agencies. The last time that they did a formal review of our ratings was really in the first calendar quarter of this year. As a result, we actually now have a stable outlook from all three agencies. Fitch raised our outlook from negative to stable, the two agencies already had us at stable. And certainly, one of the factors that they had cited back in 2004 when we acquired TXU Gas as a concern was the level of weather exposure that we had as a result of that acquisition. And of course, as Pat has mentioned and as we've talked about earlier on the call, that has now really been eliminated with respect to Mid-Tex. We already had weather normalization in our other Texas operations and now we've added it for Louisiana. So we have gone from having a much lower level of weather protection to now around 90% or perhaps north of that. Clearly, that pleases the agencies. They like to see stability and cash flow from our utility operations and I think with that, we have gone a long way towards achieving that. That being said, we're not of course on review for an upgrade from any of the agencies and I don't think that's going to happen in the near future. But clearly getting weather normalization in Mid-Tex and Louisiana is a huge step and we'll continue to work on the other areas, including reducing our leverage organically as Pat mentioned and taking other steps over time.

Okay, thank you.

Matthew Lemme, UBS.

Good morning everyone. With regard to the stepout into midstream, you had mentioned that you were approached by some producers. So should I take that to mean that this is more of a one-off type project, or do you have a stated strategy on midstream, and should we expect some more announcements?

We do have a strategy longer-term to be in the -- what I would call gathering business, not all of the midstream businesses, but we have seen opportunities particularly in service areas that we serve. We are not looking to go in other states that we're not involved in, but this project happened to arise in [Kentucky] (technical difficulty) where we serve the utility and are very familiar with. So we will continue to be looking for opportunities in the marketing place for the marketplace for gathering projects because it really ties into our total (technical difficulty) marketing operation and some of these gathering projects we can buy gas for our marketing company to resell. We can earn on the project itself. So really, as I mentioned earlier, we see ourselves in three lines of business -- Distribution, Pipeline and Storage, which would include Gathering; and then Marketing. We're not going off into liquids plants and that kind of midstream operation. We're just looking for good, solid investment opportunities and these will be fee-based businesses where we -- we're not going to build -- I'm going to be clear about this -- we're not going to build capacity that we haven't signed people or producers or others up who will take the capacity and pay us a fee. So we are certainly not in the business of doing any speculative building -- building the pipelines. But as other opportunities arise and as those opportunities provide us with good returns which exceed our cost of capital, we will be looking for other gathering projects.

Thank you very much.

(Operator Instructions). [Nick O'Grady], (indiscernible) Asset Management.

Good morning. My question is a follow-up to I think the JP Morgan question on cash flow. It makes perfect sense to me that you levered up for the TXU acquisition and sacrificed some credit ratings. But like you mentioned, the cash flow hasn't really materialized at this point. And you're also paying out nearly 70% of your earnings in dividends. Is there maybe going to be a lowering of the dividend payout ratio? Even at the high end of your range, you'd be over 55%. When we go forward, even if we see the earnings stream come in, could we expect a lower rate of dividend growth if you expect to accrete equity? Because right now, you're levering up faster than you're creating retained earnings.

As Pat mentioned earlier, one of the reasons that our cash flow has been impacted is because of the warm weather that we have experienced in Louisiana and Texas and because we didn't have the rate design changes that we've now achieved in place. So we're looking at this coming fiscal year starting October 1 as our cash flow will be much stronger than it heretofore has been. We have no plans to lower our dividend. In fact, we know that the dividend is a very important part of why people invest in us. We have been raising the dividend about $0.02 a year the last five years, and we would expect to continue that. Where we would like -- our longer-term goal has been to get our dividend payout ratio down in the 65 or 70% range in kind of accordance with our peers, and then we would look -- longer-term, we would look to raise our dividend commensurate with our earnings growth. So that would be our goal as we look forward.

I guess I wonder with cost of capital probably having come up since you made the acquisition, longer-term financings may cost more and the working capital usage of the marketing business also is probably becoming more expensive. So is that going to be another drain on cash I guess over the next nine months? I don't know if you have any maturities coming up soon.

No, we really don't. We have a $300 million piece of floating-rate debt that matures at the end of -- or, in October I think of next year. But really what our significant over the next nine months use is for working capital for purchasing gas and we have made strides in improving our purchased gas recoveries from customers to improve cash flow. We've also filed a $60 million rate case for Mid-Tex that refreshes cost of capital and other elements. So Bob touched on it. When we give guidance and when we prepare our budgets, we use 30-year normal weather assumptions because that's the way our rates are set but we have not seen that really in about eight of the 10 prior winters. So we cannot really overestimate the importance for earnings and cash flow of these rate design changes in our two largest jurisdictions of the Company. And so I think it's really a tribute that with this warm weather, we have been able to not see our debt to cap ratios creep up from where they were, and so we're looking forward to making progress this year.

On the weather front, I understand that as well, but also, you're seeing market across the industry declining usage, irrespective of weather. Every new home that is built uses more efficient heaters; it has been the trend has been going on for 20 years, it seems to be accelerating. Are these mechanisms going to also have more of a decoupling piece to them?

Absolutely. Every place we filed, we filed for decoupling, including in Texas. Interestingly, as we did the due diligence on this Mid-Tex acquisition, we did not see the same level of declining use in the state of Texas. It was kind of curious and the new construction that is taking place in our DFW Metroplex and down near Austin are larger than average homes with more gas usage, gas lanterns, things like that. So I think that explains part of it here. And it's 50% of our customer base, and top line, not net customer growth but top line customer growth, it's more like 2% here, which helped. But the fact that we are in 12 states, there is a lot of rate activity. We're always filing. We have a filing pending in Missouri and our big Texas filing. So we're very active on the rate front. And every time we file, we're asking for margin decoupling and we're starting to see -- we're starting to get some traction on that in the industry. It has sort of been a ground swell. Even the rating agencies -- Moody's put out a position paper on margin decoupling. So [Naruke] is very focused on it, and in the states where we operate, we're seeing some receptivity to it. So I think that can only help.

Thanks for the answers guys.

There are no further questions at this time. I will now turn the call back over to Susan Giles for closing remarks.

Thank you all. Let me remind you that we do have a recording of the call available for replay on the Web site through November 7. We do appreciate your interest in Atmos Energy and thank you all for joining us this morning.

Thank you. The concluded today's conference call. You may now disconnect.