安特吉 (ETR) 2011 Q3 法說會逐字稿

Good day, everyone, and welcome to the Entergy Corporation third quarter 2011 earnings release conference call. Today's call is being recorded. At this time, for introductions and opening comments, I would like to turn the call over to Vice President of Investor Relations, Ms. Paula Waters. Please go ahead, ma'am.

Good morning and thank you for joining us. We will begin this morning's comments from Entergy's Chairman and CEO, Wayne Leonard; and then Leo Denault, our CFO, will review results. In an effort to accommodate everyone with questions this morning, we request that each person asks no more than two questions. After the Q&A session, I will close with the applicable legal statements. Wayne?

Okay, thanks, Paula. Good morning, everybody. We know many of you are preparing for the EEI Conference next week. Many other companies in our sector are reporting this week also. With that in mind, or comments will be brief, or at least relatively brief for us, and limited to quarterly results and recent events. We will discuss strategic issues with you at EEI.

Starting at the Utility, on October 28 the Arkansas Public Service Commission issued an order in its show cause proceeding on post-system agreement transition issues for Entergy Arkansas. In its order, the APSC decided that it is prudent for Entergy Arkansas to join a regional transmission organization.

However, the Commission did not make a determination on the question of which RTO was in the best interests of Entergy Arkansas and its ratepayers -- the Midwest Independent System Operator option or the Southwest Power Pool RTO option. A decision on which RTO to join was not the original subject of this docket, which was opened in February 2010, and as such the ATSC deferred any determination on Entergy Arkansas' proposal to join MISO until the Company files an application to transfer operational control of its transmission facilities to MISO.

The ATSC order provides helpful guidance on the upcoming change of control filing that Entergy Arkansas will make in the next 30 days.

Similar change of control filings will be made in the other retail regulatory jurisdictions by year end, starting with yesterday's filing with the Louisiana Public Service Commission. Upon its exit from the system agreement, Entergy Arkansas proposed to join MISO, which would provide it as well as the other utility operating companies more benefits from the commitment and dispatch to a larger system than currently provided by the system agreement. These benefits derive from joining an RTO with substantial scale and a day-two market.

As you know, day two refers to an RTO that includes day-ahead and real-time energy markets. MISO has a functioning day-two market today that will generate savings for our customers on day one. SPP does not. Even though cost benefit analysis completed to date optimistically assumes SPP will have one by December 2013, both schedule and costs are highly uncertain, particularly in light of the challenges other RTOs have experienced in transitioning to day-two markets.

Even assuming an operational day-two market in SPP, MISO is expected to provide 25% greater benefits than SPP.

The system agreement was the subject of another ruling late last month by the Federal Energy Regulatory Commission related to its 2005 bandwidth decision. FERC's 2005 decision established the requirement that each utility operating company's production costs be roughly equal within plus or minus 11% of system average production costs and set 2007 as the first year for payments based upon production costs for calendar year 2006.

In its latest order, the FERC rejected arguments to require refunds for a 20-month period spanning September 2001 through May 2003. However, the FERC concluded the bandwidth remedy should have been implemented sooner by calculating bandwidth remedy payments and receipts for the 7-month period starting June 1, 2005, the date of the FERC's initial order, rather than January 1, 2006. We are currently reviewing the order and are in the process of calculating the amount of payments required between the utility operating companies.

As is the case with bandwidth remedy receipts, these payments and receipts will be calculated based upon the detailed formula prescribed by the FERC staff. It is likely the effect of moving up the implementation date for the bandwidth remedy will result in additional payments from Entergy Arkansas. But as a reminder, Entergy Arkansas has an existing rider approved by the APSC that provides for a recovery of costs resulting from the FERC 2005 orders and any subsequent modifications of these orders.

Immediately after the FERC order on rehearing in late 2005, Entergy Arkansas gave the required 96-month notice of its withdrawal from the system agreement. That exit is now 26 months away, and Entergy Arkansas is actively preparing for this exit.

In another development relating to the proposed move to MISO, a FERC ruling in late September provided important procedural guidance regarding the path forward for obtaining certainty on key issues affecting the operating company's participation in MISO. At issue was a transitional waiver requested by MISO regarding proposed transmission cost allocation provisions associated with Entergy's integration into MISO. The FERC concluded that the waiver request was not the appropriate vehicle for obtaining FERC approval for the proposed provisions and, instead, these type of provisions should be sought through specific tariff changes and accompanied by additional details.

MISO recently made public the proposed tariff changes and is currently working through its stakeholder process to finalize and file the appropriate changes. This approach will provide greater clarity for Entergy's retail regulators and customers on the cost allocation policies that will be in effect for the operating company's customers as we integrate into MISO.

In other regulatory events at the Utility, formal rate plan filings for the 2010 test year were resolved in Louisiana and New Orleans. At Entergy New Orleans, the city council approved a settlement that will result in a $13.1 million reduction in electric rates and a $1.6 million reduction in gas rates, effective the first billing cycle in October. This is the fourth straight year of rate reductions due in part to continued sales strength from the city's rebirth following Hurricane Katrina as well as unseasonal weather in 2010. The average residential electric rate for Entergy New Orleans customers is now more than 22% below 2008 levels.

Also last month, the Louisiana Public Service Commission approved formula rate plan reports for Entergy Louisiana and Entergy Gulf States Louisiana resolving their 2010 test year filings. The final reports reflect 2010 earnings consistent with each company's authorized bandwidth returns, resulting in no cost of service changes. However, the LPSC deferred to its November meeting motions for a one-year extension of formula rate plans through the 2011 test year, as proposed by Entergy Louisiana and Entergy Gulf States Louisiana. As part of the proposed extension, each of the Louisiana companies indicated that they would file a full rate case by May of 2013, primarily to determine cost of service rate classes and the appropriate rate structure. This timing would also allow consideration of any potential rate making issue associated with the proposed transition to MISO.

In Texas, after completing an overall review of cost, Entergy Texas submitted a notice last week to the cities in its jurisdiction of its intent to file a rate case. The rate case is expected to be filed by year end and, under Texas law, a final decision is due within 185 days of filing.

Wrapping up at the Utility, in October, Entergy filed for review for a stay in the implementation of the US Environmental Protection Agency's Cross-State Air Pollution Rule, or CSAPR, in the US Court of Appeals for the District of Columbia. In addition, Entergy filed directory with the EPA to request a delay in implementation and reconsideration of the basis for the final rule. Numerous utilities, states and other parties also filed challenges to CSAPR, including the public service commissions in Louisiana and Mississippi and the state of Texas. We believe the rule is well intended but seriously flawed due to insufficient modeling capability and inaccurate inputs to that model.

As a result, it incorporates some fundamental errors based upon inappropriate modeling applications that could threaten the utility operating companies' abilities to meet the needs of its customers without subjecting the companies to the risks of large fines for noncompliance. The primary issue for Entergy is the potential inability to serve our customers and to comply physically on the shortened timeline created by the final rule, especially if interstate allowance trading is also limited. Utility operating companies are still reviewing the rule as well as last month's proposed revisions to the rule.

Specifically, items under review include likely allowance pricing, unit operations and dispatch options and a potential installation of pollution control equipment that can be installed by next summer. Even with the EPA's proposed revisions to the rule, the Entergy states are still disadvantaged on allowances. The revision would be a step in the right direction and is more realistic because it takes into account the necessity for some units around the country to operate through the load pocket needs and transmission constraints even if they don't run in the model that EPA used.

For example, it is well known in our service territory that the areas in Amite South and west of the Atchafalaya Basin, or what we call WOTAB, presents substantial service complexities. They are dead-ended to the south by the Gulf of Mexico, and in the case of WOTAB, also to the West by ERCOT. These constraints limit the amount of power that can be imported into the area and therefore make stable generation by existing facilities in the load area essential to maintaining reliability. The revised rule would also allow unlimited interstate allowance trading until 2014 that is increasing the liquidity in the allowance market.

However, most of the states are still significantly short allowances and methods for compliance are still under review. As it stands today, CSAPR is effective next year unless the courts issue a stay. An appeals court decision could take 12 to 18 months.

In the Entergy Wholesale Commodities business, in Vermont a three-day trial was held in mid-September in our federal lawsuit to block the state from forcing the Vermont Yankee Nuclear Plant to close in March of next year despite the fact that the NRC has issued a license to operate for another 20 years. A ruling by the District Court should be issued at any time now. However, this case is very likely headed to higher courts regardless of the decision.

In New York, a hearing before the Administrative Law Judges of the New York State Department of Environmental Conservation, or the DEC, began October 17. As we have previously discussed, at issue are several matters identified in the water quality certification and water discharge permit proceedings for Indian Point. Three issues will be covered in the first place -- the efficacy or performance of our wastewater screen proposal and whether the DEC staff properly denied the WQC application based upon the impact, if any, of the leakage of radiological material into the groundwater beneath Indian Point. Future hearing dates have not been set but are expected to resume in December.

On other issues such as what impact, if any, Indian Point has on the stated best use of the Hudson River and any endangered species and the availability of cooling towers as the best technology available -- final decisions by the DEC could be up to two years away and are appealable to New York State courts.

With expiration of the Nuclear Regulatory Commission's operating license in December -- in September 2013 for Indian Point 2 and December 2015 for Indian Point 3, we are still in the early stages of these license renewal processes. That said, the NRC issued a decision early September denying intervening requests filed in the aftermath of the Fukushima event to suspend the license renewal processes for all plants, including those for Pilgrim and Indian Point. A similar late-filed contention arising out of Fukushima by the Massachusetts attorney general is the last item pending before the Atomic Safety and Licensing Board in Pilgrim's license renewal proceeding.

There is no reason to believe that the contention filed in the Pilgrim proceeding is any different from all the other similar request that have been denied by the NRC. Appeals by Pilgrim Watch on recent ASLB decisions denying contentions they raised also remain outstanding with the NRC. The NRC's stated target for reviewing license renewal applications is within 22 months if there is no hearing and within 30 months if the hearing is required. That was the case in Pilgrim.

Over the course of more than 69 months, the longest license renewal proceeding in history, the NRC's staff has completed an in-depth review and the ASLB has resolved all admitted contentions. On the basis of these two facts, in August we filed a motion that the Pilgrim license renewal is justified under the NRC's immediate effectiveness rule and asked the NRC to direct its staff to immediately issue the 20-year license renewal. The NRC has not ruled on that motion yet.

As it relates to timing, the NRC Chairman stated in a letter sent last year to Senator Kerry that NRC regulations permit operation beyond the expiration of the current license if a final determination on Pilgrim's license renewal application has not yet been made. That refers to the timely renewal doctrine.

Wrapping up recent developments at EWC, last week we announced the acquisition of the Rhode Island State Energy Center, a 550-megawatt combined cycle gas-fired power plant located in the ISO New England market. The purchase price was $346 million, approximately $593 per kilowatt including a planned 33-megawatt upgrade scheduled for completion prior to acquisition.

Consistent with our disciplined point of view-based strategy, this investment adds stand-alone economic value, but it also starts to diversify into EWC's portfolio across fuel type and dispatch merit, and provides a valuable backstop against firm sales from Pilgrim or Vermont Yankee, thereby reducing unit-contingent discounts compared to levels we have experienced in the past. The economic value of the unit has less to do with the cost to build it or replace it or even comparable units than you might think. It has more to do with competitive positioning. How efficient is the unit compared to the general stack at that location? What are the transmission constraints or availabilities under various scenarios? Who are the likely customers and what are their product preferences?

Besides outright economics, what are other barriers to entry into that area? It's a long list, but it comes down to evaluating the plant on an option basis and the investment optionality it provides your total portfolio closing this target for this year pending federal regulatory approvals and other conditions.

In closing, I am proud to report that Entergy was named to the Dow Jones Sustainability North American Index for 2011 and 2012. This marks the 10th consecutive year Entergy has received this prestigious recognition for its leadership in sustainability. This year, key categories where Entergy ranked among the very best were occupational health and safety, corporate governance, price and risk management, Scoreboard measurements and, of course, climate strategy.

Our approach to climate change was also recognized in September by Entergy's inclusion in the Carbon Disclosure Leadership Index for the seventh time in the last eight years. Despite the challenges we are facing today, we continue to set new financial and operational records along with continued leadership in sustainability.

For example, Unit 1 of the Arkansas Nuclear 1 Plant just completed 530 days of continuous operation, setting a new record run for that site. And a $207 million securitization financing that closed in September for recovery of costs from the canceled Little Gypsy Project was at approximately 2% coupon rate. That was one of the lowest fixed rates coupons ever achieved by Entergy or any of its subsidiaries.

Also financially, our revised 2011 earnings outlook is consistent with another record year in operational earnings per share. I believe that's something like 12 of the last 13 years that we've set a new record.

Now I turn the call over to the Leo to review more of the specifics. Leo?

Thank you, Wayne, and good morning, everyone. In my remarks today I will cover third-quarter results and cash flow performance, followed by a few comments on capital deployment and our updated 2011 earnings guidance. As Wayne noted, we will keep our comments brief and focused on the quarterly results and a few recent events. We will see most of you next week at EEI, where we will discuss longer-term strategic issues.

Starting with our financial results, on slide two, third-quarter 2011 earnings were higher at the Utility compared to a year ago, while results were lower at EWC and Parent and Other. Third-quarter earnings included accretion from share repurchases. The lower share count is due to effect of repurchases completed in both 2011 and 2010. Operational earnings were up significantly compared to third quarter 2010. This increase is due largely to a tax settlement agreement with the IRS. The settlement covered several issues, the most significant related to the mark-to-market income tax treatment of the utility power purchase agreement. Slide three summarizes the effects of the settlement.

The net effect of the IRS tax settlement was $382 million reduction of income tax expense. Entergy Louisiana will share a portion of the benefits with customers, consistent with the intent of the original tax benefit sharing agreement. In a settlement approved last month by the Louisiana Public Service Commission, Entergy Louisiana will make annual payments of approximately $20.2 million to customers over the next 15 years. Accordingly, Entergy Louisiana recorded a $199 million regulatory charge net of tax and a corresponding regulatory liability to reflect this obligation. The factors driving quarter-on-quarter results for each of the segments are summarized on slide 4.

At the Utility, the tax settlement and corresponding regulatory charge for the sharing arrangement were the primary drivers for quarter-over-quarter earnings growth. Excluding these items, Utility net revenue was slightly lower than a year ago. Retail sales increased 2.4% compared to the third quarter last year or 2.6% on a weather-adjusted basis. However, net revenue was down in spite of benefits from weather-adjusted sales growth and regulatory actions. Lower unbilled revenues provided the offset due to milder weather in the unbilled sales period at the end of the quarter. Unbilled sales -- or the utility sales statistics provided in table 4 of the release reflect billed sales, while revenue also includes the effect of unbilled sales.

Weather was again a significant factor for the quarter. It was essentially flat to last year on earnings per share basis. This year was the warmest August on record, and our system saw several new records. System load for the month of August was highest in Entergy's history, breaking the previous record set in August of 2000. Three of the operating companies set new all-time peaks.

Most of the retail sales growth came in the industrial sector. Entergy Louisiana, Entergy Texas and Entergy Mississippi had the strongest industrial sales growth for the quarter. The industrial sales trend was similar to what we've seen in previous quarters, where expansion is continuing to drive the increase in industrial sales, partially offset by weakening in paper, pipeline and wood products segments. Year-to-date, total retail sales growth for the utility is 2.4% on a weather-adjusted basis, higher than the assumptions used in our full-year guidance due to stronger industrial results.

Regulatory actions also contributed to net revenue in the current quarter. Results reflected 2010 Entergy Texas base-rate adjustment as well as the Entergy Louisiana regulatory action associated with the Acadia acquisition earlier this year. These items were partially offset by the October 2010 rate decrease at Entergy New Orleans.

Also contributing to the Utility earnings increase was lower non-fuel operation and maintenance expense. Decreased O&M is due in part to lower compensation and benefits expenses, the absence of amortization of rate case expenses for Entergy Texas in this quarter last year and the deferral of previously expensed outage cost pursuant to the Entergy New Orleans regulatory agreement.

Moving on to Entergy Wholesale Commodities, this year's third quarter results declined versus 2010, due primarily to lower net revenue and higher effective income tax rate. Net revenue for EWC's nuclear portfolio declined as a result of lower energy and capacity pricing. For the EWC nuclear fleet, the average realized price for the third quarter of this year was approximately $56 per megawatt hour compared to $61 a year ago. Lower pricing was partially offset by higher nuclear volume. Operationally, EWC's nuclear fleet had an excellent quarter, producing a 98% capacity factor compared to 91% last year. The third quarter of 2010 included a portion of the scheduled outage at Fitzpatrick, while there were no refuelings in the third quarter of this year. There were also fewer unplanned outage days, 14 days in the current quarter compared to 26 days in the same period a year ago.

A higher effective income tax rate also contributed to EWC's lower results. The higher rate was driven by the absence of the reversal of the tax reserve and the net effect of consolidated tax adjustments. Both were recorded in the third quarter of last year. You may recall the consolidated tax adjustments affect the individual lines of business but net to zero at the Entergy level. Partially offsetting these factors was lower non-fuel operation and maintenance expenses, partly due to lower compensation and benefits expenses.

Finally, third-quarter Parent and Other results were lower than a year ago, due primarily to higher income tax expense at Parent and Other activities. The income tax expense increase was due primarily to the absence of a reversal of the tax reserve in the third quarter of last year, which resulted from a favorable tax court decision. The absence of consolidated tax adjustments recorded last year also contributed to the income tax increase at Parent and Other.

Moving to slide 5, we review operating cash flow performance for the quarter. While 2011 OCF was lower than last year, the decrease was due to absence of roughly $700 million we received of 2010 storm financing proceeds from Louisiana. Absent that item, OCF increased largely due to higher deferred fuel collections. Intercompany tax payments did contribute to a line of business variances that were offsetting between Utility, EWC and Parent and Other.

Now turning to slide 6, we provide some additional details on our recent agreement to acquire the Rhode Island State Energy Center, or RISEC, a 583-megawatt combined cycle plant, including a planned upgrade to be completed prior to our purchase. The RISEC acquisition aligns with our market-based point of view. This modern and efficient generation asset is well-positioned to benefit from expected market recovery and it complements the existing business by allowing more contracting flexibility for our portfolio of assets in the Northeast. The agreed-upon purchase price is approximately $346 million, subject to closing adjustments.

The acquisition will be financed similar to other non-utility investments and will utilize available corporate resources. Assuming closing by year-end, we expect the asset to produce earnings per share in the range of $0.07 in 2012 based on forward natural gas and energy prices at the end of September 2011.

Just one point on our long-term financial outlook -- Entergy has an outlook to deploy up to $4 billion to $5 billion through dividends and share repurchases from 2010 through 2014, absent other attractive investment opportunities. We continue to affirm that outlook.

Now turning to our share repurchase update summarized on slide 7, during the quarter we completed $75 million of share repurchases, buying 1.1 million shares at an average price of $66 per share. All of the repurchases were made through the existing $500 million Board-authorized program. Year to date, we have completed 150 million of share repurchases. Recall that no buybacks were assumed in 2011 guidance.

Consistent with past practice, we will continue to evaluate share repurchases against other capital deployment opportunities, considering current business conditions and investment needs as well as liquidity and financial flexibility.

Slide 8 details our updated 2011 earnings guidance. The net effect of the IRS and LPSC settlements discussed earlier is significant enough by itself to move 2011 results outside our original guidance range. Therefore, we revised our 2011 as-reported and operational earnings guidance in the range of $7.15 to $7.65 per share with a midpoint of $7.40. The updated range takes into account year-to-date income tax expense adjustments above a level assumed in the original guidance including the IRS settlement agreement, net of the amount to be shared with the Entergy Louisiana customers.

In closing, as Wayne said, we plan to review our longer-term outlook at the upcoming EEI Conference next week, similar to our past practice of the last two years. At that time, we also plan to initiate 2012 guidance and review the details on key drivers for 2012, provide a preliminary roll forward of our three-year capital plan for 2012 through 2014, summarize our long-term financial outlook and discuss longer-term strategies and opportunities.

And now the Entergy senior team is available for your questions.

(Operator instructions) Paul Patterson, Glenrock Associates.

Trying to just -- when we go over the $1.02 of IRS benefit, you guys are showing sort of an $0.80 increase. Is that because you guys had anticipated some sort of benefit, it just was a much lower amount?

That's correct, Paul. In our planning for the year-end guidance, we typically go through on a tax perspective what we believe may or may not show up during the course of the year to help set not only the midpoint range, but the midpoint, but the guidance range. And so we had anticipated some level of tax benefit showing up during the year, and the settlement is bigger than that. But we had about $40 million or so of tax benefits already baked into our guidance, so the $0.80 is the increment (multiple speakers) above what was already there.

Okay. Now, I know you guys are going to be giving guidance and everything at EEI. And I can't wait for that, but just any sense as to how we should think about taxes, the potential tax situation or effective tax rate that we should be thinking about for 2012?

Well, we will frame that up when we get into the guidance at 2012. It's kind of difficult to talk about it in isolation without talking about earnings in general.

Okay. Just the other thing I just wanted to touch base was on the growth of customers versus sales. It does look like customers are using less outside the industrial area. And I was wondering if you guys thought that was a temporary thing or whether or not you thought that that might rebound next year or if you are seeing something that you think might be more permanent, sort of the kind of stuff that we see on the gas side, maybe.

This is Gary Taylor. Yes, I think what we have seen in -- probably in a broader context is pretty similar to what you've seen along the region, is when you think about residential, they tend to really affect the price elasticity quite a bit. Their bills were up about 10% to 15% with high heat. I think we've seen an impact of that playing through, so I think that's one factor.

Energy efficiency is playing through as well, in all classes, and we factor that into our plan. And we're kind of seeing the same with commercial as well, where commercial is really following what you've seen in the economy. So as the economy recovers, we would expect commercial to come back. Industrial has actually been very, very strong, as Leo said, actually stronger than we would have expected. And our overall sales are a little bit above our existing plan.

And if you think about how Entergy's positioned, I saw some EEI data that basically says for the Southeast, sales weather-adjusted were up about 1.5% this year, and we were up about 2.5% overall. But what we should see is, as price mediated a little bit, residential should come back up some. And commercial is going to pretty much follow what we think the economy is going to do. We'll talk more at EEI what we expect as far as sales next year.

Okay, great, thanks a lot.

Steve Fleishman, Bank of America.

Two questions -- first, on the accretion from the transaction, obviously -- I think you generally finance this with cash on hand or debt. But in theory, it also replaces other uses of cash like potentially more buybacks. So when you are giving the accretion estimates, are you doing it -- how are you thinking about the financing? Is it essentially -- are these accretive versus other ways you would've used this money?

Well, that's accretion on a whole, excluding financing. And you are right; it's fungible in terms of whether it comes out of incremental borrowings or utilizes dollars that we otherwise would have used for the buyback. So it's not net of that in terms of what we reported.

So it's not net of any financing costs or -- or just net of like use of the bank lines or something?

Yes, it's not net of any real financing costs.

Okay. And is this accretion -- I'm sorry -- is this accretion including the benefit to the Company on the local nuclear plants in terms of maybe selling the power differently or not?

No, it's not.

Okay. So it's without financing costs, but also without changing the way you are selling the nuke?

Correct.

Okay. One other question -- when you look at year to date, the benefits if you go to your little table, the benefits of like sales and rate actions year-to-date, I think, is $0.15 a share versus last year, from page 9. And when you gave guidance, I think that you had expected that to be $0.45, but it seems like sales have been pretty good, and I'm not aware of any surprises on rate actions. So I'm curious why that is trailing, or is there a big fourth-quarter catch-up?

Well, one aspect of it is the delay in Waterford 3 that was supposed to be in rates this year, and now will be next year.

Okay.

A delay in closing of Acadia by a month -- that was factored in as well.

But are you booking AFC on those things, so it's not really earnings impactful, or it is?

It's not exactly as good as putting them in rates.

Okay.

Acadia, there was not because it was an acquisition. But there would be fewer dollars because of the spend being delayed in Waterford. The AFUDC will just be on the portion that has been expanded as opposed to all of it being in rates earlier this year.

Okay, okay, thanks so much.

(Operator instructions) Neil Mehta, Goldman Sachs.

Hi, this is Neil Mehta here for Michael Lapides, lots of O&M improvement in the quarter. Can you walk through again with the key levers were and if there were any unusual items embedded in that O&M?

The key drivers for the O&M decrease is really lower compensation and benefits expenses, has been the biggest driver between this year and last year.

Got it, and then separate question -- your debt refinancing plans at the holding company, especially related to the credit facility next year -- can you provide any color related to that?

You should see us probably start to take action on the credit facility here in pretty short order. We've got until August of 2012 before that expires, so certainly around the first part of the year we will get that taken care of.

All right, I appreciate it, guys.

Ashar Khan, Visium Asset Management.

Good morning, congrats. Leo, just going back to -- so can we assume that, as you had mentioned in your assumptions, that weather was like $0.62 positive last year and you expected that to -- normal would have been a $0.62 range negative, that as weather has been pretty much flat year-over-year, you have kept the majority of that $0.62 this year versus losing any. Would that be a fair comment?

You are right; weather has been flat year on year. When we moved guidance, Ashar, we didn't take into effect anything other than the incremental tax position. So we didn't incorporate anything into the move of guidance for weather. We didn't include anything in it as it relates to reduced pricing in the Northeast, we didn't include anything in there as it relates to the Waterford 3 delay that we were just talking about. So you are correct that we've seen about $0.57 of weather I think this year, which is pretty close to what we saw last year.

I think you asked about that, actually, on last quarter's call, and I think I told you not to count third-quarter weather this year, just like last year. And I don't know what you knew about the weather that you would know it would come out exactly the same on an earnings per share basis. But I think we had the $0.29 last year and this year both.

Okay. And then just going back to Steve's question, as you said, you had factored in like $0.45, and then only it seems like probably $0.20 would show up this year. Can we then assume that this $0.25 that didn't show up this year is really, as you are saying, going into next year rather than this year? Is that a fair thing to say?

In terms of the rate actions and load growth?

Right. You had mentioned $0.45 for sales growth and rate actions. So as you're saying, year to date we might end up around $0.20 versus the $0.45. So can we take the remaining $0.25, as you mentioned, some of the factors got delayed -- can we assume that these are, then, reflected next year?

Well, next year, you will see the full-year impact of Acadia and -- when the assets didn't get in rates this year get in rates next year, you will see that step up from there, yes. That will be included in what we come out with in guidance for 2012.

And the other thing -- the Waterford 3 steam generator project is not scheduled to be completed until the end of 2012, so you wouldn't see any impact of it until basically 2013.

Understood, but the amount that we lost, like $0.20 this year or so, they have really been delayed to '12; right? That is what has happened? So it's not that they've gone to '13? Or have some moved to '13 as well?

The Waterford 3 will be toward the end of the year next year, so it won't be a -- you won't get a full year of it. You won't get as much in next year as we would have had this year.

Okay, okay, okay, thank you so much.

(Operator instructions) Reza Hatefi, Decade Capital.

-- on the weather question. So I guess since it's the great whether you've had this year is not included in your revised earnings guidance, how should we think about that as you finish the year? Is it just -- once you print your fourth-quarter numbers, does it all of a sudden show up? I'm kind of just confused on how to think about that.

There will be a variety of things, I guess, that will kind of get into the end-of-year number. Again, we haven't made adjustments for weather, the lower capacity and energy pricing in the Northeast, the Waterford 3 delay, etc. So I guess one way to think about it is the low end of the range is probably not something that we would be looking at by the end of the year.

And I'm sorry if you answered this earlier, but O&M this year -- I forget what the earnings impact was when you originally guided last EEI. But how does that track versus your original guidance? And would you consider maybe spending some O&M here to sort of offset the good weather you've had, bringing it forward, I guess?

Well, certainly, when you have the kind of weather we've had, you'll have a situation where the plants are running more, the system is stressed more. And so there will be O&M associated with that at both the generation and TD basis. So some of that might just be incremental, some of it certainly would be having to do maintenance on facilities sooner than we otherwise would have thought we had to because we are running the system harder because of the weather. And actually, it's two years in a row, so that's certainly a possibility that you see O&M pick up to match the kind of operational characteristics of the system in this kind of weather.

Okay, okay, thank you very much.

That will conclude our question and answer session today. At this time, I would like to turn the call back over to Paula Waters.

Thank you, Carolyn, and thanks to all for participating this morning. Before we close, we remind you to refer to our release and website for Safe Harbor and Regulation G compliance statements. Our call was recorded and can be accessed for the next seven days by dialing 719-457-0820, replay code 4650540. This concludes our call. Thank you.

Thank you, everyone, you may now disconnect.