埃特莫斯能源 (ATO) 2007 Q1 法說會逐字稿

Thank you for standing by. Welcome to the Atmos Energy Corp. first-quarter conference call. During today's presentation all parties will be on a listen-only mode. (OPERATOR INSTRUCTIONS). This conference is being recorded today, Wednesday, February 7, 2007. I would now like to turn the conference over to Susan Giles, Vice President of Investor Relations and Corporate Communications. Please go ahead.

Thank you, Heidi. 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 be happy to take any questions about them at the end of our prepared remarks.

If you would like to access the webcast and slides, please visit our website AtmostEnergy.com and click on the conference call link. Also we plan to file the Company's Form 10-Q later today.

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 me today are Bob Best, Chairman, President and CEO, and Pat Reddy, Senior Vice President and CFO. We have other members of our leadership team available to assist with questions as needed. With that I'll turn the call over to Bob Best who will review the highlights of our fiscal 2007 first quarter. Bob?

Thank you, Susan and good morning, everyone, and we want to thank all of you for joining us. We certainly as always appreciate your interest in Atmos Energy. We are coming to you this morning from Nashville, Tennessee when in a couple of hours we will hold our annual shareholders media. I'm pleased to report to our investors listening on this call and to those that will join us in our annual meeting the very strong financial results for the first quarter fiscal 2007. Pat Reddy, are Chief Financial Officer, as Susan mentioned, will review the results in detail in just a few moments, but before he does I want to make a few comments about the first quarter.

Yesterday after the market closed we reported a 14% increase in net income and a 10% rise in earnings per diluted share. We also announced our 93rd consecutive cash dividend. Our indicated annual dividend rate for fiscal 2007 is $1.28 per share. As you've seen from earnings release our non-utility business delivered outstanding results again this quarter. They continued to execute on their strategy to capture favorable spreads, although in a less volatile natural gas market than we experienced a year ago.

The pipeline and storage segment of our business continues to perform well. The four pipeline projects in Texas that we began last year are now complete and in service and are contributing to our revenue stream. As you read in our press release, we are evaluating the scale, scope and timing of the Strait Creek mid-stream gathering business in Kentucky. We are certainly committed to making prudent and timely decisions about this project once our evaluation is complete. We continue to believe in Eastern Kentucky that there remains a need for additional pipeline to support the producers in that region.

The utility operations also delivered solid earnings in the quarter. We were please to see -- very pleased to see in fact the benefits of WNA in our Mid-Tex and Louisiana divisions. While the utility operations still have minimal exposure to the impact in weather, for the most part we've insulated ourselves from the extreme financial effects of unseasonable weather patterns in the 12 states that we serve.

The key message in today's discussion is that our unyielding focus on rate design has delivered results. Implementing weather normalization in Mid-Tex and Louisiana this heating season has positively impacted our gross profit by almost $8 million in the first quarter alone. We certainly are seeing the results that we anticipated. Never before in our company's history has there been more activity in the rates and regulatory arena. We currently have rate cases pending in Texas, Missouri, Kentucky and Louisiana and have planned filings in four additional states. I'll talk about these rate cases in the Mid-Tex Division's recent proposal for decision later on in the call.

As you also know, in December we successfully completed our public offering of 6.3 million shares of common stock. We used the $192 million in net proceeds to reduce our short-term debt. At quarter end our debt to capitalization ratio was reduced to 54.9% from [61]% at September 30th. As a result of the success of this offering we are now within the range of our debt to capitalization commitment while not reducing our earnings per share guidance for fiscal 2007.

We have solid investment-grade ratings and in early March we will be visiting the rating agencies to discuss our continued progress. Now Pat Reddy, our Chief Financial Officer, is going to review the complete financial results for the quarter and after Pat finishes I'll be back for a few closing comments and then we'll be glad to take questions. Pat?

Thank you, Bob, and good morning, everyone. My remarks will focus on the results for the quarter and then I'll discuss our fiscal 2007 guidance since we didn't get the chance to present that to you at our scheduled analyst conference due to the overlap with our December equity offering.

As we said in the earnings release, consolidated net income for the quarter reached $81 million, an increase of 14% over the prior year quarter. Earnings per diluted share were $0.97 compared to $0.88 for the prior year period, an increase of 10%. The significant drivers of our earnings results for the quarter were the solid performances from our non-utility businesses, particularly with unrealized mark to market gains at the marketing company offset in part by lower than expected utility results and an anticipated overall rise in O&M expenses across all segments.

The utility segment delivered about $32 million of net income in the quarter compared to $48 million in the same period a year ago, a decrease of 34%. The non-utility operations added over $49 million of net income in the quarter compared to about $23 million a year ago, an increase of 119%. Of that the natural gas marketing segment delivered $35 million of net income and the pipeline and storage segment contributed about $14 million.

Now let's take a closer look at our earnings drivers quarter-over-quarter. Consolidated gross profit in the current quarter increased $29 million to $376 million. Utility gross profit declined about $18 million to $263 million as a result of a few factors. The single biggest driver of the decline in utility gross profit quarter-over-quarter was a $15 million reduction in revenue associated with franchise fees and gross receipts taxes primarily in our Mid-Tex Division as a result of lower natural gas prices this year which are recovered from utility customers.

Under our franchise agreements with our Mid-Tex cities timing differences arise due to the differences between current gas prices and throughput which determine current franchise fees and revenues and the corresponding expense which is calculated using prior period gas cost and volume. The time period used to calculate franchise fees and gross receipts tax expense, primarily again in our Mid-Tex Division, is known as the privilege period and is established in each individual franchise agreement for the hundreds of cities that we serve.

Typically the privilege period lags the current period anywhere from one to 18 months. The lag effect of calculating the revenue and the expense using a different time period can be material during periods of volatile gas prices. These timing differences may favorably or unfavorably affect net income in the period, but they offset over time with no permanent effect on net income. We have included a schedule in the appendix on page 50 of our slide deck that shows the impact on gross profit and tax expense for the current quarter and the same quarter last year and the variances between both periods.

Quarter-over-quarter throughput was down by almost 7 BCF as a result of weather that was 4% warmer than the prior year quarter. Although about 90% of our utility margins are now protected from the effects of weather, with any WNA mechanism there will still be some imprecision and that uncorrected weather exposure negatively impacted our utility gross profit by about $9 million this quarter. Implementing WNA in our Mid-Tex Division on October 1st, and in our Louisiana Division on December 1st, helped to offset the impact of weather exposure and increased our gross profit by about $8 million. However, the net impact for the current quarter was still a negative $1 million on gross margin.

We also experienced about a $2 million decline in irrigation and industrial consumption. However, effects of the group filings in Texas and the rate stabilization filing in Louisiana have added almost $9 million this quarter as compared with the prior year quarter. Our natural gas marketing gross profit for the quarter increased by about $37 million to $63 million for the quarter. The single biggest driver was a $37 million increase, if deposited, mark on our storage margin. For the current quarter the storage and marketing margin includes a positive unrealized mark to market gain of $49 million compared with an unrealized loss of about $29 million in the prior year, a positive swing of $78 million quarter-over-quarter.

As you know, these unrealized gains and losses are primarily caused by differences in Nymex futures prices used to hedge inventory and spot prices used to value the physical hedged inventory. In the current year quarter we saw the spreads collapse. At September 30th the market spread was about $5.25 per BCF of gas in storage and at December 31st the spread had contracted to just $1.32 per BCF. The market spread continued to compress in January. Additionally, the mark to market impact is magnified this quarter by 8.2 BCF of additional physical gas in storage compared to the same quarter a year ago. We believe that over time these unrealized gains and losses should reverse at the time of delivery and sale of the inventory.

Operationally we experienced a decrease in our realized marketing margins of about $9 million quarter-over-quarter. This was largely due to realizing lower margins in a less volatile market. You'll remember that a year ago (technical difficulty) unprecedented price volatility in the aftermath of hurricanes Katrina and Rita. We also experienced a decrease in our realized storage margins of about $32 million quarter-over-quarter. This was the result of capturing more favorable arbitrage spreads related to our storage optimization efforts in the prior year quarter, again due to greater market volatility coupled with the strategic decision we made in the current quarter to leave gas in storage and to buy flowing gas to meet our customer needs which should have the effect of improving arbitrage spreads in future periods.

Let me remind you that Atmos Energy marketing endeavors to maintain a flat trading book and avoids mismatches between the volume of gas in shortage and a number of associated financial hedges. AEM does not engage in speculative trading and it uses financial hedges to lock in an economic gross profit margin at the time it enters into a storage transaction. Therefore the mark this quarter just reflects market value at a particular point in time when our gas is cycled from storage and the financial hedges are settled as planned these marks are eliminated. However, at the end of any period, for financial reporting purposes, our storage book can add significant unrealized gains or losses to our storage margin. But the economic gross profit we captured in the original transactions will remain essentially unchanged.

The embedded value of our storage book is quantified in the appendix to the slide presentation on pages 52 to 53. 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 the reporting period. At the end of December economic value of volumes held in storage was about $61 million. The GAAP value recorded in unrealized trading margin was an unrealized gain of almost $33 million, yielding an increase in future gross profit of about $28 million.

Based on the current setup and assumptions at the end of the current period the recognition of about $61 million of economic value in realized trading margin would straddle our fiscal 2007 and fiscal 2008 with the bulk of that income expected to be realized by March of 2007. The timing of the unwinding of the $33 million of unrealized gains currently recorded on the books is dependent on the embedded spreads and market spread.

The pipeline and storage segment gross profit improved by $10 million to about $50 million. The Northside Loop and other compression projects that Bob referred to and which we focused on last year added $4.3 million in incremental margin this quarter. Our most recent GRIP filing for Atmos Pipeline Texas added just over $1 million. Additionally, Atmos Pipeline's storage margins benefited from capturing more favorable arbitrage spreads on asset management contracts including an unrealized component because the risks associated with these contracts are hedged resulting in an increase in total margin of about $5 million quarter-over-quarter.

Consolidated operation and maintenance expense for the first quarter rose $7 million to $115 million. The rise in O&M in the current quarter is primarily due to increases in employee costs as a result of additional headcount and increased benefit costs somewhat offset by the nonrecurring $2 million charge for Hurricane Katrina related losses incurred in the first quarter of last year.

Our provision for doubtful accounts decreased $2 million from the same period a year ago primarily as a result of the impact of lower natural gas prices. Our current rate on bad debt expense equates to about 7/10 of 1% of residential and commercial revenues before recoveries. As a reminder, our yearly O&M expense increases about $20 million annually and is typically somewhat front loaded in the first two quarters of our fiscal year.

Turning now to taxes other than income taxes, in the quarter they were $40 million, down about $5 million from the same period a year ago. This is primarily due to lower franchise fees and state gross receipt taxes resulting from lower revenues because of lower gas prices. Again, to see a breakdown of this impact please see the appendix to our presentation on page 50.

Our interest charges for the quarter were about $39 million, up $3 million because of higher average short-term debt balances in the quarter. So I'll remind you, we used the $192 million in net proceeds from our December equity offering to reduce short-term debt, so we should see a decline in interest expense going forward.

Looking at cash flow for the quarter, we generated operating cash of $165 million compared with cash outflows of about $195 million in the same period a year ago, or a favorable swing of $360 million. Last year's first quarter was greatly impacted by the effect of higher natural gas prices on our working capital management efforts. The drivers of that effect include changes in Accounts Receivable and gas stored underground increased operating cash by $457 million; improved management of our deferred gas cost balances increased cash by $86 million; also lower cash required to collateralize our risk management account increased our operating cash by $29 million. But despite these several operating cash impacts in this quarter we did experience $226 million of unfavorable timing of Accounts Payable and other accrued liabilities.

Turning to our capital expenditures -- CapEx for the quarter was about $87 million, down about $15 million from the same period a year ago basically due to the absence of capital expenses related to our Northside Loop and various pipeline compression projects that were completed in the third quarter of fiscal 2006.

Now, as Susan mentioned, I want to spend a few minutes talking about our earnings guidance for 2007. We're maintaining our previously announced earnings estimate for fiscal 2007 in the range of $1.90 to $2.00 per diluted share of common stock. Our assumptions underlying this range include the dilutive effect of 6.3 million shares from our equity offering in December with an average outstanding share count of about 87.6 million shares which, as we've said before, gave rise to about $0.05 per share of dilution from that offering.

We're also depending upon a fair and reasonable outcome in our Mid-Tex division rate case. It's certainly premature at this point to make any changes to guidance as a result of the hearing examiner's recommendations in the proposal for decision, and we'll await the commissioner's final order which we expect to receive in March or early April. And we'll analyze the commission's final decision in detail before we determine how the final order will impact our financial results.

We also have taken into account volatility in natural gas prices which caused Atmos Energy marketing to report a $49 million unrealized mark to market gain in the first quarter. Natural gas spreads will likely continue to be volatile, and while that's good for our marketing operations, it also means that the impact from mark to market accounting on that business can cause unforeseen swings of both gains and losses in the trading margins of that business.

We have revised upward the marketing and asset optimization margin contribution for fiscal 2007 to a range of 95 to 105 million due to changes in natural gas spreads through January and the marketing team's ability to continue to capture favorable spreads. We also have assumed 30-year normal weather as prescribed by regulators in the states in which we operate without WNA or margin decoupling and also no material acquisitions in the balance of our fiscal year.

We expect the following ranges for several complements of net income for fiscal 2007 -- operation and maintenance expense in the range of $453 million to $460 million; depreciation and amortization expense in the range of $206 million to $212 million; interest expense in the range of $142 million to $144 million; income tax expense in the range of $101 to $105 million; and net income of $166 million to $175 million to arrive at our EPS range of $1.90 to $2.00 per diluted share.

Capital expenditures for fiscal 2007 are estimated at between 425 and $440 million with 251 to $262 million in maintenance CapEx and 174 to $178 million in growth capital. Of course the growth CapEx number could change based in part on the outcome of our analysis of the Strait Creek project. We will diligently pursue the right decisions on this project and we will provide an update once we have clarity on the project's design. Now once again here's Bob.

Thanks, Pat. I'll make a few summary comments and then we'll open the call up for any questions that you may have. As Pat has just reported, it's been a very solid quarter for the Company. We delivered double-digit growth in both net income and earnings per share and we feel very good about that accomplishment. Our non-utility business continues to generate, as they have for the last several years, very remarkable financial results. The gas marketing group continues to perform well and add customers. And their pipeline storage segment is continuing to realize good financial results from our four Texas projects.

We mentioned earlier the Strait Creek project and we are continuing to work to bring that project to fruition. And I mentioned we believe there are volumes to support that project. And we see -- as we move forward with this project we'll see other projects I think that will be spawned from the Strait Creek project. We also are looking and will consummate what we call the Park City system in Western Kentucky which will gather shallow low-pressure gas and will cost in the range of 2 to $3 million.

As I also mentioned at the outset, we're pleased with our rate design changes in Louisiana and the Mid-Tex division which contributed $8 million this quarter. We will continue to focus on rates and rate design in all of our utility divisions. In December we filed a comprehensive rate case in Kentucky for an increase of $10.4 million or 4.6% increase in total revenue and it's our first case that we filed there in seven years. The filing includes a rate stabilization mechanism as well as requested ROE of 11.75%. And we anticipate the Kentucky Public Service Commission will set a procedural schedule in that case very soon.

As a result of the comprehensive rate filing in Kentucky, the Kentucky Public Service Commission suspended the procedural schedule related to the attorney general's complaint and the Commission is considering dismissing this case at our request. Also in December 2006 Trans La filed its RSC filing. We requested a revenue increase of $1.8 million and this deficiency is largely due to the rate stabilization clause's ability to capture [loan] declines which occurred since our last filing and other rate base additions. This filing is under review with implementation scheduled for April of this year.

As you may recall, last October the Tennessee regulatory authority voted to reduce rates by $6.1 million effective December 1, 2006. And we are currently assessing the timing of a new rate case filing in Tennessee since we believe our rates in Tennessee have now become deficient.

In Missouri a tentative settlement has been reached with the Commission staff on the $3.4 million rate case we filed last April. The staff is recommending a zero change in revenue but substantial changes in rate design including a basic fixed variable component. Is successful Missouri will join Louisiana and Mississippi as the third jurisdiction for Atmos to achieve margin decoupling. We anticipate a final order by March 7th.

And we remain diligent in achieving a favorable outcome in the rate case filed last May in our Mid-Tex division. A proposal for decision, which is actually a recommendation to the Commission, was issued in the Mid-Tex rate case last Friday and the proposal recommended a revenue decrease of $22.8 million and a refund of $2.6 million. But the decision also supports a continuation of weather normalization which has been in effect since October 1. The next step of the proposal is a full review by the Texas Railroad Commission.

We remain optimistic that the Commission's decision will be reasoned and fair as they have done in the past. Our optimism is based on the fact that the Commission has consistently issued decisions which seem to strike a balance between the consumer's right to receive service at just and reasonable rates and the utility's right to recover prudently incurred costs and the opportunity to earn a reasonable return. We are currently reviewing the decision and we're going to be filing exceptions on February 12th. We still believe our filing is a good filing; a $60 million filing, as I said. We remain optimistic about the outcome.

The last time TXU gas filed a rate case they actually received a further rate reduction than we received and then the Commission turned that around. So as I say, we believe that we will receive a fair decision and one that will confirm the validity of a rate increase for our company.

Our fundamental business is delivering safe and reliable natural gas under the rules of our regulatory agencies. And the states that we serve in all of these cases are steps in the long process of setting rates in a regulatory environment and allowing us to continue to serve our customers safely and providing good customer service, and at the same time earning a fair rate of return for our company. The Company remains committed to growing our earnings 4% to 6% a year on average, and we have done that for the last six years, and this would be the seventh consecutive year that we have been able to achieve that goal.

Maximizing return on investments and focused, as I mentioned at the outset, on keeping our capital structure within the 50% to 55% range. We continue to believe that this earnings growth profile and our dividend yield is attractive to those that invest in us and provide good value to our shareholders, and we will continue to keep this momentum going as I said, as we have over the last six years.

This concludes our remarks, and now we will be happy to answer any questions that you may have.

(OPERATOR INSTRUCTIONS) [Matthew Lynn], UBS.

Good morning, guys. Two questions related to the marketing and trading business. One, I noticed the $10 million expected mark for the year, so obviously, the market is going to come in a little bit. I was wondering, and I realize that this is unpredictable, but what are the assumptions in the $10 million, going from the plus 50 we have now to plus 10? What does that assume happens over the next three quarters and how that unwinds?

I am going to ask Rick Alford, and Mark Johnson who are here with us from our marketing company to address that question.

This is Rick Alford, Matt. What we have in the assumption for the remainder of the year is that as you see on page 53 of our slide deck, our market spread is about $1.32 per decatherm on 21 BCF of gas in the ground. And it is impossible, as you know, to predict what the market spread will do between now and the end of the year. But our original assumption of $10 million of unrealized income in our original projections, we have moved that up and based that on the market spread remaining somewhere in the $1.31 range throughout the end of the year.

Okay, great. Then my second question also related to marketing and trading is the volume of gas and storage was up, and you guys highlighted this earlier in the prepared remarks, was up pretty significantly year-over-year. Is that a function of the warm weather; in other words, you didn't unload as much gas as you thought you would? And going forward, is that a more normal amount that we would expect to see or would we expect it to decline?

We will let Mark Johnson, Head of our Nonutility Operations, address that.

Certainly the weather plays a role, but more importantly the amount of gas we have in storage for our account is more dependent on the opportunities and the term structure of the futures. And we keep -- we manage our storage to optimize the highest value that is out there on the marketplace going forward.

So going forward then, I guess what you are saying is we might see the size of that position come down or grow up just depending on how the market goes?

Absolutely. If your plot month is a stronger month and cold weather is upon us and cash is very strong, it then becomes an opportunity for you to withdraw gas out of storage and at that point then you reposition your hedges.

Remind me how much storage capacity you have in total.

Storage capacity that we manage or that we have the opportunity --

I guess that you have access to.

That we have access to -- we manage between 37 and 38 BCF a day. However, not all of that is really available to us to optimize. A lot of that we just manage for our customers. And I guess what I would say is that the most we've ever had in storage in our account is roughly the 21 BCF that we showed at the end of September.

So we're pretty much maxed out right now is what you're saying?

We are very close to our maximum ability to maximize storage.

Okay, great. Those are my questions. Thank you very much, guys.

Angela Ho, Wachovia.

Good morning. Congratulations. Just got a quick question on the rate case in Mid-Tex. The $22.8 million revenue decrease, is that mostly coming from the examiner's recommendation on a single block rate design for residential and commercial customers? Is that really their major contention or can you explain a little bit about that?

Yes. There are four or five, Angela, major areas that the examiner addressed and we'll just really have Pat go over those. We won't try to go over every issue that was addressed. But Pat, why don't you just hit the high points?

Angela, I think the changes in the block rate and in the monthly customer fixed charge really are the by product or the output of the hearing examiner's recommendations. And thinking about some of the biggest differences between the $57 million that we've requested and the nearly $23 million reduction that the hearing examiner has proposed would be things like the difference between the 10% rate of return on equity that we're currently recovering versus his recommendation of 9.7%, and using our actual capital structure versus our proposed hypothetical structure of more like 50-50. That's about a -- those two things alone are about a $14 million reduction from what we filed.

And then any time you reduce the revenue requirement you're going to reduce the federal income taxes that you have to pay and that's about $12 million as we see it in that decision. One other large component or difference between our filing and what the hearing examiner has proposed is that at the time that we purchased TXU gas from TXU they had a substantial amount of deferred taxes on the books which are a reduction in the rate base that the utility earns on. And the theory there is that you can -- for tax purposes you can use an accelerated depreciation which saves you cash, but then you can't also earn on it in your rate base.

At the time that that sale was made to us TXU Corporation settled up with IRS and repaid those deferred taxes zeroing out that balance. And so under accepted regulatory precedent and under IRS tax law we're required to restore and zero out that deduction and start over again basically with our accelerated depreciation. And the judge looked at that and said that that could increase cost of service and wasn't a good idea and disallowed it. We think that's inappropriate ratemaking and an incorrect tax result. So that's about a $12 million item.

And then there were a number of different changes that he made to our cash working capital allowance expecting, for example, that we'd securitize receivables as TXU Corp. did despite the fact that we said that under our various state regulation we're not allowed to do that. And also applied lead and lag for pipeline based expense payments and other payments. Using TXU Corp.'s history that's about an $8 million reduction. And then there were some other reductions related to shared services allocation factors.

Instead of using our cost allocation manual percentages that we filed and that we use in all 12 of our states the examiner imposed a different standard. That's about an $8 million change. And then changing our shared services depreciation expense to use a different standard was another $7 million. So anyway, we could kind of go on down the list, but it was really just not accepting our internal methodologies that we've used, again, for years in each of our 12 states to allocate our shared services expenses, our overhead and our depreciation. And so those are just differences between what we filed and then that comes out as a change in the rate, but I'd say that's a byproduct, Angela.

Great, thank you. And then you were mentioning about how last time (indiscernible) you filed I guess the examiner recommended something even lower. And then the Commission kind of turned it around. Do you remember how much they actually -- (indiscernible) you actually got from that rate case?

The examiner in the last -- of course, you know we're not predicting anything. Every case is different. But the examiner recommended a $42 million rate reduction and TXU actually received an $11 million rate increase. So it was a $53 million turnaround.

Perfect, thank you.

Paul Patterson, Glenrock Associates.

Good morning. Can you just go over page 53 once again? I'm looking at this and just to make sure I understand it -- you're saying that you guys basically booked about $60 million of economic value and about $33 million of that showed up in mark to market and the rest will be realized over the rest of the year, is that right?

This is Rick Alford again, Paul. There's actually a little bit more to that. We do have $60.6 million of economic value, as you pointed out, at the end of December. However, if you'll back up to September of 2006 we had a negative $16 million of mark to market value which turned around by $48 million, $48.8 million to a positive $32.8 million in the quarter. So we went from a negative mark at the end of September to a positive mark at the end of December.

Okay. And so the difference between the 60 and the 32 should be realized over the rest of the year is what you guys are suggesting?

Well, all of that 60.6 will be realized at some point in the future. The 27.8 which you see over in the market spread number will be hitting income at some point in the future and, as Pat said, it will straddle the 2007-2008 fiscal years. But the $32.8 million has been run through the income statement as unrealized income. So we do have a future impact on our gross margin of 27.8 and that will be a combination of realized and unrealized.

Okay. And then also I guess I wanted to touch base with this. I saw that O&M went up and you mentioned that there are higher employee and other administrative costs. I was just wondering, is there anything specifically that's driving that?

Paul, we compare this quarter versus the prior year quarter and so we talk about the inflation affect. But when you think about our results versus budget, these are anticipated increases. Our employees got on average a 3.5% wage increase last year. We have inflation in our medical expenses and we actually have a slide in the deck that shows our year-over-year increase for employee benefits and retiree benefits and I think that will give you a pretty good picture of what those increases are, but they certainly weren't unanticipated.

Okay, but I mean I saw the medical slide, would you say that's what's driving most of that (multiple speakers)?

That plus the salary increase of 3.5%.

Okay. And then looking at the franchise fees and the privilege period that you were talking about, looking at slide 50 am I correct in seeing that that's about $10 million that you guys got this year so far that -- I mean, how dose that work? Is it really a balancing account in which that actually reverses or is it just something over time there's going to be a mismatch and you can expect it to be one way one quarter and different --?

It's the latter, Paul. We don't have a balancing account like we do for purchased gas cost. And when you think about it, we have a jurisdiction with a franchise agreement that looks back to last year. In November of last year we were billing out our gas cost at a little under $16. This year it's more like $7.00 to $8.00 or roughly half. Years ago when gas prices were pretty stable around the $2.00 to $3.00 range you wouldn't get much of a mismatch, but with these extreme differences in gas prices we are.

So we're evaluating our options. I think of us as sort of a toll booth or a toll collector. We recover revenue and we paid it to our franchise jurisdiction. We'd like to think of the current period expense and revenue and there's a couple different ways to do that. One would be to renegotiate our franchise agreement in the way the privilege period works. Another might be to adjust our tariff to sync up recovery of the expense on a current basis. But those are things that will take a little while.

But last year, by the end of the year we were within $2 million of our revenue and expense matching up. So it's not a perfect offset, but over time, over kind of a 12 to 18 month period those will tend to offset. But in any one quarter, like this quarter, it could be a significant variance item.

Okay. So in your numbers that you've very helpfully put out there, what are you guys expecting for the privilege period? Is it pretty much similar to what you got last year?

Yes, we're pretty much expecting it to plus or minus $15 million two zero out by the end of the fiscal year.

Okay. Then there's also a little statement in your press release that you might considering -- that you're considering several things to pay for the upcoming bond maturity. And it mentions internally generated funds, debt and equity potentially in the public markets. I was just wondering if you could give us more of a feeling for what your thought is in terms of potential equity if you guys might want to issue some more of that.

We haven't really thought about that and I think that's really just general language. It reflects the approvals that we got in our shelf filing. And Laurie Sherwood and Bob and I and others will be talking about what to do with that $300 million of floating-rate debt that matures in October. We've got some alternatives and also we have upcoming meetings, regularly scheduled meetings with our rating agencies. And we'll certainly want to discuss some scenarios with them. But we're really not at this point contemplating an equity issuance. We have a certain amount of equity that we put out every year under our various plans, our company match and the 401(k) and our direct stock repurchase plan, etc., but beyond that, that's really it for now.

Okay, thanks. I appreciate it.

Faisel Khan, Citigroup.

Good morning. I wanted to see if you could help me foot some of your revenue increases from rate adjustments on page 6 to the revenue for the annual rate increases you have on page 36. So talk about $6.7 million in net increases and on page 36 you've got like a $39 million approved annual rate increase. I'm just trying to figure out if you can help me bridge the gap there. Is it timing or -- because you're expecting 39 minus 6.7 to kind of occurred during the '07 period?

As you know, the 6.7 reflects the increases that have already been achieved and then we have several large cases -- well, one very large case that's pending in Mid-Tex's case. We have cases in Missouri, we're filing in Tennessee and Kentucky. And so the difference would really reflect -- and plus a number of GRIP filings that we'll be making for Mid-Tex, for Atmos Pipeline Texas and for West Texas. And that $6.7 million is just for the first quarter, that's not the annual number because these other proceedings haven't been settled yet.

So the $39 million you have on page 36, it says 2006.

Right.

That hasn't all occurred yet you're saying?

Oh, I'm sorry, I was looking at the '07 to '11, the 35 to 45 for the year. You're talking about our prior fiscal year?

Yes, if I look at kind of if I look at the year-over-year decrease in operating income I'm trying to figure out how this $39 million in rate increases would have filtered through into this year.

We have our actual rate increase proceeds in our K for our last fiscal year and we could look back at that with you.

That's okay. So the $6.7 million is what? This should be something that reoccurs quarterly, there's no seasonality to it? Is that (multiple speakers)?

No, not at all. It just depends on when we file and when cases get resolved and basically for '06 you can see that $34 million of that $39 million were our GRIP filings in Texas and that's obviously the lion's share. The other roughly 5 million were non-GRIP increases and those are basically the actuals that we received for the year. The lion's share obviously was GRIP.

Because when I look at the operating income at the utility and I add back the $15.2 million in the tax issue, I'm trying to figure out how -- I should have operating income that goes up year-over-year, but it's actually kind of flat year-over-year. So I'm trying to reconcile that and I think that you talked a little bit about the O&M, the O&M increases and those are very large increases. Do you have the ability to pass that on through your rates and get recovery of that?

As long as these expenses are prudent and just and reasonable we do have the opportunity to recover them. We don't in some cases have the automatic ability to update rates. We have, for example, in Louisiana and Mississippi annual filings that we make to refresh rates for O&M changes and other changes. In Texas we have the opportunity to update the capital piece of our investment and expense during the year, not the O&M piece. You have to file a new rate case to refresh rates for increases in O&M in Texas, for example, and that's about half of our utility customer base.

So on page 13 when you talk about the $8.4 million increase in employee costs and the $2.8 million increase in administrative costs, is that kind of -- should we kind of annualize those numbers? Is that how we should look at it -- those increases?

I think we said in our release that those tend to be a little bit front loaded in the first two quarters, a little bit like our heating season. And so it's really more in the first six months, I don't think you can annualize that.

Okay, fair enough. And you said that these are increases that in some of your jurisdictions you would actually get to recover at some point in time?

Yes. And even in Texas -- what we do basically, Faisel, if you look at all elements of your cost of service and if we determine that we're deficient in terms of our actual earned rates of return versus our allowed rate, then we'd go right in with a new rate filing to refresh rates. And at most you have some lag associated with that, but ultimately you can recover those increases in your rates.

And have these increases kind of been -- if I look back historically, I mean have we seen these sorts of increases in the past too on an annual basis?

Yes, but actually the rate of increase has slowed down some because we've gone from having healthcare increases in the 17% range down closer to 10%. So the rate of increase has slowed down. You may remember going back a couple years ago we flipped around from having pension credits to pension expense. And so the rate of that increase has gone down. So yes, this is kind of a typical increase and, as we mentioned in our release, we have about $20 million each and every year of incremental O&M and medical and employee benefits that go up that we need to recover and that's why, as Bob mentioned, we've never had more rate activity in the Company than we have right now.

Fair enough. Thank you.

You're welcome.

Adar Zango, Zimmer Lucas Partners.

Good morning. The drivers of higher marketing gross margin guidance, I wanted to know if any of these are ongoing or are these higher margins purely a reflection of the '07 environment. And do you still see an 8% growth rate on the fee-based margins which you've now raised to about $52 million relative to about $44 million as of Q4?

We continue to try to grow our marketing margin and, as we've talked about in the past, that is the more stable part of our business. However, our storage operation's results depend so much on the volatility in the marketplace we really can't predict where that's going to go in the future. So to say that in '08 we'll be continuing to go up I think would be a little out of place for us. But I think the '07 numbers are just reflecting the extreme volatility that we have in the marketplace. And you can see that by the numbers that we have on page 53. An excess of $5.00 market spread is very, very unusual.

Okay. And is there any normalized marketing level that you could speak to going forward?

I don't really know that we can right now. We will likely look at the numbers that we had in our original assumptions for our '07 budget and build on that slightly. But it's really too early right now to respond to that question.

Okay, thank you. And just one question. Regarding the weather impact this quarter, can you just say which jurisdictions were hit and was any of this from Mid-Tex or Louisiana?

It was primarily in Louisiana because our WNA period didn't begin in Louisiana until December, and then October and November -- it cost us about $7 million of pretax gross profit in Louisiana for the effect of weather. And then in our other jurisdictions it was pretty much just an offsetting.

Okay, thank you.

Jim Harmon, Lehman Brothers.

A couple of quick questions. I'm not sure how much additional color you can provide on Strait Creek, but I'm curious to know whether or not you're still getting firm commitments from producers, that's the first question and then I'll ask the second. Are you still continuing to evaluate additional projects at pipeline and storage? And at the marketing affiliate I think you infer that you were maxed out at storage and so maybe down the line might we see more storage investment there?

I'll address both of those. I think to your second question, we're looking at certainly other gathering projects. So they would be on a smaller scale than Strait Creek, but we've got some good prospects. I mention the one in Kentucky that we're working on and bringing to finalization. We are looking at storage projects as well and that certainly would hold tremendous promise for us in the future and Mark Johnson is here and Ron McDowell that works for him in business development and they've got that on their radar screen.

I'll address Strait Creek. We've had memorandums of understanding with 11 producers in that area and we're trying to firm these contracts up. As you know, there's another project in the area, so we're trying to make sure that before we move forward with putting pipe in the ground that we have firm agreements and that we feel very confident about the geology and the reserves that would be attached.

At this moment the project -- we should know within the next few weeks whether we will proceed with Strait Creek and under -- if we may change the scale and scope of that project. But right now we still are cautiously optimistic that we'll have a project. And the fellas here are working on it. In fact, some of them are headed up that way from Nashville after we finish this meeting to try to finalize these agreements. As I say, we're cautiously optimistic.

Okay. That's great. And actually I lied. I do have a third question for Pat. What's your deferred tax component for '07 cash flow?

As far as the guidance?

Yes.

Okay, let's see. I don't think we have that readily available, Jim.

We'll get back to you with that, Jim. Susan is here, she's taking notes furiously so she'll give you a call.

Okay, great. Thank you very much.

Josh [Goulden], JPMorgan.

Good morning. I just have a quick question and I'm hoping that you can help me understand a little bit more. Turning back to slide 53, the marketing division, the $60.6 million in economic value versus the $32.8 million as an unrealized gain. Can you help me sort of with the cash-flow statement and when will the $60.6 million be realized in the cash-flow statement?

As you pointed out, Josh, the $60.6 million is the cash impact that we expect sometime in the future. Now that cash impact will straddle the fiscal 2007 and 2008 years and it's expected, based on our setup at the end of December, it's expected to be realized primarily in fiscal '07, most of that in the second quarter.

Okay. So the $60.6 million should primarily flow through in the second quarter of '07?

Yes, but keep in mind, Josh, that we have realized, as you pointed out, $32.8 million of unrealized gains. So as those positions roll off that unrealized gain will reverse (multiple speakers) realized gain.

Where will that show up? Where will that show up? In the working capital portion?

It will show up in our income statement and our gross margin and it will show up in terms of cash received from settling those positions and also from cycling gas.

Okay. So it'll just come through [FFO]?

Yes, and to your point that's when the cash is actually realized.

Okay, thank you, gentlemen. I appreciate it.

Brooke Glenn Mullin, JPMorgan.

I think most of my questions have been answered, but just real quickly -- the industrial decline at the utility, is that a few large customers leaving? Do you have any sense as to weather that's going to continue in terms of deterioration or if you could just give us any insight on what you're seeing on the industrial side?

Brook, at this point based on one quarter I don't think we have any firm conclusions about that. I would say that on our system we don't tend to have fertilizer manufacturers and people that are extremely sensitive to gas prices and moving offshore, so we really haven't seen that. What we have seen over the years is trends just with the basic economy. For example, we serve the GM Saturn plant in Tennessee and from time to time they'll close a second shift or start a second shift and that can impact our volume.

But at a macro level I don't think we're seeing anything in this quarter that would bode for ongoing declines. Because if anything with gas prices back at the $7.00 to $8.00 level, most of the industrial customers we serve are profitable at that level. So, that's not real specific, but Mark, I don't know, on the marketing company side have you seen any trends with respect to industrial customers?

No, we've been very successful in adding industrial load. So we're not monitoring it on an individual decline. (inaudible) very strong.

The growth in industrial customer base for our marketing company has been very strong. We've picked up some marquee names in the last quarter that have added to our business. So I don't think we see a trend to that.

Brooke, I would also say if you're looking on page 6 in the slides it says there's a $2.3 million decrease due to industrial/irrigation consumption decline. And we have seen, as we've talked in the past, a significant decline over the last really 10 to 15 years in our irrigation market in West Texas and we actually wrote down those assets at the end of 2006 because we saw that decline as one that was continuing that was not going to reverse.

So I think that's probably where we've seen the most decline. We really haven't seen a whole lot of change in our industrial market and in fact I think if you read nationally that it's been amazing that there hasn't been the decline in the industrial market that you might expect even with high gas prices last year.

Thank you. I just have one other question on the rate case in Texas. One of the adjustments that you mentioned was for depreciation. If we think about the impact potentially on net income, would that be something that you would change the way you actually report depreciation if the hearing examiner's depreciation would go through?

Yes, we would. For GAAP purposes we have to conform depreciation expense with what we're authorized in rates. So if there is a reduction in expense it will help income and decrease current period cash-flow a little bit. But, yes.

So from net income it would essentially be a wash?

Correct.

Thank you.

Thank you. At this time we have no questions.

That concludes our remarks today. Thank you all for joining us and, again, if you have any additional questions, please call me or Rose [Blessing]. Have a good day. Thank you.

Thank you.