安特吉 (ETR) 2010 Q3 法說會逐字稿

Good day, everyone and welcome to the Entergy Corporation third quarter 2010 earnings conference call. Today's call is being recorded. At this time, for openings and introductions, I would like to turn the call over to Miss Paula Waters of Investor Relations. Please go ahead.

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

Thanks, Paula. Good morning, everybody. With the EEI Financial Conference just over a week away, our earnings release and our comments today will be limited to significant and recent events in 2010 financial performance. We will provide with you an update on our longer term financial outlook at the EEI.

Starting with the utility, the Public Utility Commission of Texas is scheduled to discuss Entergy Texas rate case at its next open meeting on November 10, 2010. At that meeting, the commission will review the ALJ recommendation regarding the competitive generation service or CGS tariff and the unopposed stipulation settlement agreement addressing all other matters in the case.

To recap how we got here, in October, the ALJ issued a proposal for decisions recommending that the CGS tariff be rejected due to the potential for substantial shift in cost from a limited class of eligible and participating customers to remaining customers thus violating the basic principle of cost causation. As a reminder, legislation initially enacted in 2005, and modified in 2009, required Entergy Texas to propose a tariff that offers eligible customers the ability to contract for competitive generation. As proposed by Entergy Texas, eligible customers would be limited to those with a minimum of 2500 kilowatts of demand.

In the proposed decision, the ALJ recognized that the law is clear. That Entergy Texas be made whole for program costs and any loss of revenues from participating customers. The decision whether to proceed with the CGS tariff and if so, under what terms, is now before the commission to complete its review as required by the Texas legislation and then to approve, reject or modify it.

The unopposed rate case settlement filed in early August reflected a $68 million rate increase and a 10.125% allowed return on equity. An initial $59 million rate increase was implemented effective August 15th, subject to refund, up from the $17.5 million increase implemented at the beginning of May. If approved, the final step up to achieve the full $68 million increase will take effect the first billing cycle in May of 2011.

As part of the unopposed settlement, the parties also stipulated to the current level of transmission investment of $464 million that will serve as the baseline for future annual filings for transition rider. That includes full return of and on additional investment above that level.

Entergy Texas expects to make its first filings to implement the transition rider around the end of 2010 or the beginning of 2011. The settlement agreement represents tangible progress to provide Entergy Texas a real opportunity to earn its allowed return. However, Entergy Texas intends to continue to work with Texas stakeholders to achieve rate recovery mechanisms that permit full recognition of Entergy Texas cost structure and estimated power needs to meet growing customer demand.

Aligning the economic interest of customers and shareholders will require efficient rate making mechanisms like formula rate plans and capacity riders. Consistent with that reality, Entergy Texas filed a petition on September 17th, which is generally supported by the other non-ERCOT utilities to initiate a rule making allowing for purchase power capacity rider to address regulatory lag by recovery of those costs outside continuous filings of base rate cases. The PUCT has 60 days to decide whether or not to pursue the proposed rule making and if the commission elects to proceed, must reach a decision within six months of publishing the rule.

In New Orleans, the city's advisers reached a settlement with Entergy New Orleans on the 2009 formula rate plan filing providing for an $18 million electric rate decrease retroactive to the first billing cycle of October 2010 and no change in gas rates. This outcome resulted largely from a continued increase in the New Orleans customer base as rebuilding of neighborhoods in the aftermath of Katrina and return of customers continues to exceed projections. The New Orleans city council is expected to consider this settlement at its meeting today.

Turning to transmission, at a recent Entergy regional state committee meeting, Charles River Associates reported the results of the FERC funded independent cost benefit study of the Entergy and Cleco regions joining the Southwest Power Pool RTO. For the ten-year period starting 2013, the study projects the Entergy region, including the entities outside the Entergy operating companies, would realize anywhere from a net cost to $438 million to a net benefit of $387 million, primarily depending upon transmission cost allocation issues.

Various addendum cost benefit studies also being conducted by Charles River's indicated -- including the Entergy system joined the Midwest ISO and stand alone studies for Entergy Arkansas joining the STPRTO or Midwest ISO are expected to be completed before the end of the first quarter 2011.

With the initial four-year term of the independent coordinator of transmission arrangement expiring next month, the utility operating companies have filed with the FERC to extend the ICT arrangement with certain modifications by up to two years. This will help provide sufficient time for analysis and implementation of other alternatives to the current structure. Entergy continues to have discussions with retail regulators to support the ERSC's evaluation process of post ICT alternatives.

In other system related matters, discussions with retail regulators continued regarding a potential successor arrangement for the Entergy system agreement. This arrangement, often referred to as the commitment operations and dispatch agreement, or CODA is designed to allow each participating company to realize the operational benefits of the larger system; including energy savings from joint commitment and dispatch and the capital savings from holding lower overall reserve margins while seeking to resolve the very real concerns expressed regarding the frequent historic litigation among the parties under the current agreement.

We have also committed that no Entergy operating company will enter voluntarily into the CODA if its regulator finds it is not in the public interest.

Before leaving the discussion of recent events in the utility business, I should address last week's announcement regarding the civil investigative demand Entergy Corp received from the Department of Justice. First of all, this is a civil investigation and not a complaint. The DOJ is exploring questions and issues on a confidential basis such as the vertical integration of the utility and practices and policies of the Entergy utility companies related to generation, procurement and dispatch and transmission. The investigation is just beginning and, of course, utilities are fully cooperating with the DOJ.

At this early stage, it is premature to speculate on when the investigation will be completed. While I cannot provide any specifics on why the investigation was initiated, I would point out that Entergy's practices, policies and tariffs have been the subject of thorough review and regulation by the FERC and the state regulators. And we believe our actions and decisions are consistent with the approvals that we have received from regulators and satisfy all applicable laws and regulations. For example, the Oasis web site contains real time information about almost anything you might ever want to know with regard to transmission.

As noted in our announcement, Entergy became aware of the investigation during the required Hart-Scott Rodino review of the utility's proposed acquisition of the 580 megawatt Acadia Unit Two. The DOJ has since indicated that it does not intend to object to the consummation of the Acadia transaction. Closing of the Acadia acquisition is targeted for early 2011, subject to the Louisiana Public Service Commission's approval. This is the fifth plant acquisition in our territory that the Department of Justice has reviewed without objection.

Turning to the Entergy wholesale commodities business, one of the top priorities is license renewal of existing nuclear fleet. At Pilgrim, NRC ruling denying an intervenience request to disqualify one of the judges on the Atomic Safety and Licensing Board panel cleared the way for establishing the procedural schedule to address the remaining contention remanded for hearing. The preliminary schedule calls for hearing by the end of the first quarter next year.

Regarding the Vermont Yankee license renewal proceeding, the New England Coalition filed a brief with the ASLB conceding that there were no further issues in dispute on the remaining matter remanded by the NRC to the ASLB.

However, the New England Coalition raised a new contention, electrical cable aging management, to which Vermont Yankee responded in mid-September. Also, during the quarter, the NRC staff issued a positive report on its audit of Vermont Yankee's license renewal application conducted in response to the tritium leak earlier this year. The staff's report raised three issues. Entergy or Vermont Yankee has addressed these three issues in an application supplement committed to the NRC in mid-October which was prepared in coordination with a similar application submitted for Pilgrim.

The next milestone in the Indian Point license renewal process is the issuance by the NRC staff of the final supplemental environmental impact statement currently expected next month. Reports released during the quarter by the independent system operators in New York and New England strongly support the criticality of these units to the system reliability in their regions. In New York, findings in the ISO's 2010 Reliability Needs Assessment indicated the unexpected retirement of the Indian Point units would cause an immediate violation of the reliability standards even considering aggressive assumptions for energy conservation in the region.

In the base caseload forecast, the probability of an involuntary interruption of load was 3.8 times higher than the reliability standard in 2020. The probability estimate declined from 40 times at the beginning of the planning period in the 2009 report, due to the combination of the economic slowdown and the state's ambitious demand size management targets.

However, sensitivity analysis using what we believe are more realistic assumptions indicated the probability of reliability violations are much closer to the conclusion in the 2009 report if you take out both of the Indian Point units. Further, the New York ISO's assessment found that the New York Department of Environmental Conservation's best available technology program, as defined under proposed rule issued in March, creates the greatest risk for premature retirements and for unacceptable reliability risks. The New York ISO's president and CEO summed it up succinctly indicating the need to carefully balance environmental policy objectives with reliability requirements of the electric system.

Further, in early August, the New England ISO denied Vermont Yankee's request to delist from the 2013 to 2014 forward capacity auction given studies completed to date. In other words, without Vermont Yankee in service, there are reliability issues which could adversely affect neighboring areas. The ISO willing to point out that any alternative to Vermont Yankee comes at an additional, and we might add unnecessary, cost.

Of course, reliability and safety concerns go hand in hand. No one takes safety more seriously than we do. On that subject, local concerns re-surfaced in Vermont following a recent finding that trace amounts of tritium in a water sample taken from rock fissures beneath the plant. It's important to note that the water sample test did not indicate any new tritium leak at Vermont Yankee. The test results confirmed the migration of water released from the previous leak which was identified, sealed, and repaired earlier this year within 49 days of detection.

Going forward, we remain committed to pursue greater prevention and earlier detection as part of the Exelon Entergy industry leading initiative on tritium. At the same time, we have upgraded our sampling process and our communications with stakeholders.

Turning to our recent price hedging activity, it's clear that the commodity markets for power and natural gas have been a tough hurdle for our non-utility business segment and will likely continue to prove challenging for the next couple of years. Forward energy prices for 2011 and 2012 in New York and New England declined by an average of 10% since the end of the second quarter and dropped by over 25% since the 2009 EEI financial conference. Consistent with past practice, we have been layering in hedges over the past year. Although, we have been more aggressive in accelerating this hedging activity based on our proprietary point of view of these markets. As a result, forward energy sold is now 95% in 2011 and 76% in 2012 at contract prices in the money by around $630 million for EWC's Nuclear portfolio.

Despite these challenging times and with the help of near record warm temperatures, Entergy's third quarter earnings per share were the highest of any quarterly period in company history. For the full year, we remain on track for a sixth consecutive year of delivering record operational earnings per share.

But we are now in a transitional period. On the one hand, we have an uncertain economic climate, challenging commodity markets and critical nuclear license renewal activities at EWC. On the other hand, there are numerous corporate development opportunities including the potential acquisitions identified in the recent long-term RFP process and alternative structures for the system agreement and transmission operations at the utility. We also continue to evaluate and consider available options at EWC to create and return value to our owners.

Many of you have asked if there will be a significant strategic announcement at EEI as has been the case at various times in the past. Given the fact that EEI is just about ten days away, I can tell you that we don't have any major events ripe for announcement at this time, but we will update you on our longer term outlook and discuss our strategies and opportunities in more detail.

While the world's economic prospects are not as bright as they once were or what we would hope for, we remain grounded in the reality that it is what it is. We are committed to sound risk management, and wishful thinking about what might have been cannot cloud our judgment and our processes. We will not leave large positions open on the basis of look back models. Nor will we substantially increase our risk by selling firm products that we can't back up.

I can assure you, we are committed to executing every day on the things we can control, taking decisive action consistent with our proprietary point of view, maintaining financial head room for unexpected opportunities or threats, while being ever attentive to the amount of risk and type of risk that we're warehousing.

In closing, I am pleased to report that Entergy was named to the prestigious Dow Jones Sustainability World Index for the ninth year in a row, a distinction held by no other US utility. Key areas where Entergy employees rank best or among the best were safety, environmental policy and climate change, corporate governance and price risk management, where we achieved the best score. Our commitment to excellence in all of these areas as well as our overarching financial aspiration, a top core total shareholder return remain unchanged.

Now, I will turn the call over to Leo.

Thank you, Wayne, and good morning, everyone. In my remarks today, I will cover third quarter results and cash flow performance followed by an update of our share repurchase activity and a recap of 2010 earnings guidance. I will also point out some highlights on financing activity over the past few months and close with a few preliminary thoughts on 2011 drivers that we'll be discussing with you further at the upcoming EEI conference.

Starting with our financial results on slide two, third quarter 2010 earnings were higher than one year ago at both the Utility and Parent and Other, while they were lower at Nuclear. Third quarter earnings included accretion from share repurchases from both the 2009 and 2010 programs. Once again, this quarter, as reported results included charges associated with spin-off dysynergies and the expenses for outside services that are now focused on the spin unwind process. As we previously committed, we have been aggressively working through the process of unwinding the spin infrastructure. These unwind efforts were largely completed in the third quarter.

Excluding the special item related to this spin, operational earnings were up 15% compared to third quarter 2009. For factors driving quarter-on-quarter results, turn to slide three. First, at the Utility, higher net revenue was the primary factor driving the quarterly earnings increase. Utility sales once again increased across all customer classes including the effect of significantly warmer than normal weather throughout our service territory. Even excluding the effective weather, each jurisdiction had positive retail sales growth. Overall, utility retail sales grew by 8.5% but by double digit performance in the residential sector. And for the third consecutive quarter, weather was a significant factor in residential sales growth.

After a record setting cold winter, temperatures across our service territory reached near record levels for the second consecutive quarter. Our region's temperatures ranked 13th hottest of the 116 years of available data in the third quarter. Louisiana and Mississippi and Arkansas temperatures were especially warm, ranking fourth, seventh, and tenth respectively. In addition, Texas experienced record usage for four straight weeks peaking at 65.7 gigawatts on August 30th.

Turning to the industrial sector, we continue to see the positive effects of the economic rebound and facility expansions. Strong industrial growth continued in the third quarter but a lower level than in the second quarter suggesting economic recovery may be leveling off. In looking at specific industrial segments, the results are mixed. Chemicals, refining and miscellaneous manufacturing had been our strongest sectors while wood products and pipelines have been weak points. Primary metals were strong earlier in the year but softened some during the most recent quarter due to weak construction markets and lower demand from China.

As we noted in the past few quarters, there are some tempering effects included in our industrial sales results this quarter. The increase in net revenue from higher industrial sales volume was somewhat offset by the price effect associated with demand charges. Recall that last year, we had the reverse situation when the demand charges had offset the negative impacts of lower volume. The key take away from all of this, is that our weather adjusted sales results to date align well with the assumptions we used in our full year guidance numbers.

Regulatory actions also contributed to net revenue in the current quarter. Results reflect the rate cases at Entergy Arkansas and Entergy Texas, as well as formula rate plan activity at Entergy Gulf States Louisiana and Entergy Louisiana. The absence of a refund reserve from the Louisiana utility companies recorded in the third quarter of 2009 also contributed.

Partially offsetting the positive effect of higher net revenue was higher non-fuel operation and maintenance expense and income tax expense. The increase in non-fuel operation and maintenance expense is due primarily to higher compensation-related expenses and higher outage costs at generating units. Higher income tax expense was partly due to the net effect of consolidated tax adjustments which are made across the Entergy companies and net to zero on a consolidated basis. Other drivers at the Utility were largely offsetting.

Moving on to Entergy nuclear, this year's third quarter results declined versus 2009, primarily due to decreased net revenue associated with lower generation, attributable to both planned and unplanned outage days, and higher non-fuel operation and maintenance expense. The third quarter of 2010 included a portion of the scheduled refueling outage at Fitzpatrick which started on September 12th and ended in the fourth quarter. There were no scheduled outages in the fall of 2009. There were also approximately 21 additional unplanned outage days compared to the third quarter last year, primarily at the Indian Points units and Palisades. Conversely, the non-utility nuclear fleet ran at a 100% capacity factor in the third quarter of last year.

On a positive note, the realized price in the current quarter was essentially flat to the third quarter of last year. While the average contract price decreased year-over-year, market prices on the unsold energy averaged nearly $25 a megawatt hour higher, largely due to higher natural gas prices and warmer weather driving stronger demand. Similar to the utility business, Entergy nuclear's third quarter non-fuel operation and maintenance expense was also higher than a year ago. This increase was due partly to higher compensation-related expenses. Partially offsetting these factors was a lower effective tax rate at Entergy nuclear, driven by a reversal of a tax reserve, as well as, net effects of consolidated tax adjustments discussed earlier.

Finally, third quarter Parent and Other results were higher than a year ago due primarily to lower income tax expense. The income tax expense decrease resulted in part from a favorable tax court decision. The net effect of consolidated tax adjustments also contributed to the income tax benefit at Parent and Other.

Moving now to slide four, we continue to have very strong operating cash flow performance. Third quarter 2010 OCF was approximately $700 million higher than the third quarter of last year. Receipt of storm financing proceeds from Louisiana was the primary driver. Other factors, both at the utility, include higher net revenues, partially offset by higher working capital requirements.

At the end of the third quarter, Entergy's consolidated gross liquidity stood at over $4.1 billion, comprised of $1.9 billion in cash and cash equivalents, and $2.2 billion in untapped revolver capacity. One reason for this strong liquidity was the Parent notes financing completed last month. With a very favorable interest rate environment, we initiated and closed $1 billion of permanent debt at the Parent company with approximately half due in five years and the balance in ten. We used the proceeds to pay down a portion of the borrowings under the Parent's revolving credit facility which expires in 2012.

We also took advantage of attractive capital markets to reduce interest costs for our customers. In the past five weeks, we executed more than $900 million of economic refinancings and an average coupon of 4.7% compared to 5.6% with the debt that was retired. We'll continue to evaluate additional financing opportunities at both Utility operating companies and the Parent.

I'll now turn to the update on our share repurchase program summarized on slide 5. During the third quarter, we completed roughly $528 million of share repurchases, buying 6.8 million shares at an average price of $78 a share. Of the repurchases during the quarter, $466 million were made through the existing $750 million board authorization program. The balance was repurchased to offset the dilutive effects of stock option exercises. As we've noted previously, we expect to complete repurchases under the current $750 million program by year end. Execution is subject to our on-going evaluation of business and financial conditions and our point of view on our stock price.

Slide six details our current 2010 earnings guidance which ranges from $5.95 to $6.80 per share on an as-reported basis, and $6.40 to $7.20 per share on an operational basis. The as-reported and operational guidance ranges remain unchanged from the numbers we shared with you in our second quarter earnings call.

As we assess our earnings performance to date, we believe we are well-positioned relative to our full-year guidance range. With $0.55 per share of weather on a year-to-date basis, I know many you are wondering why we did not revise our guidance range. It is simply due to our guidance practice to maintain the range unless factors move us out of that range. We instead provide insight on how the major drivers are performing relative to the original guidance assumptions. It is not meant as an indication of significant risk to our guidance range that we've not discussed with you. In fact, at this point in the year, we will note indications are, that we'll end up above the midpoint of $6.80 of operational earnings per share.

In closing, as Wayne said, we plan to update our long-term outlook at the upcoming EEI conference which starts on October 31st. At that time, we plan to initiate 2011 guidance with all the typical details on key drivers you're used to receiving. We also plan to provide the usual preliminary roll forward of our three-year capital plan for 2011 through 2013 as well as an update of our long-term financial outlook.

In advance of that, turning to slide seven, we wanted to provide a few preliminary thoughts on 2011 earnings drivers. For example, we know that the utilities 2010 sales growth has been very strong and includes significantly positive effects from weather and economic recovery. On the other hand, we also know that we've already achieved positive results in the regulatory arena which will benefit next year.

For Entergy Nuclear, we have observed declining price trends. However, we have only three refueling outages planned for 2011 compared to four for 2010. We also have the $750 million share repurchase program that we expect to complete by year end with the full share effect realized in 2011.

We're looking forward to seeing you at EEI to fill in more details of our financial outlook, strategies and opportunities. And now, Entergy's senior team is available for your questions.

(Operator Instructions) And we will take our first question from Steve Fleishman with Bank of America Merrill Lynch.

Yes, hi guys. When you look at the new hedges that you added, it appears on the surface that the pricing of those new hedges was quite low versus where market is even considering unit contingent hedging. And the only thing I can think that could explain that would be maybe you hedge mainly in your low-priced regions like upstate New York? Does that explain it? Or are we just calculating it wrong?

Leo?

Steve, I don't really want to get into plant by plant where we're hedging out. But certainly, there's some significant differences between zones. There's some significant difference between plants. Just as you mentioned. And so, obviously the average price of those sales are going to be driven by where we did the hedging as well as what type of hedging we've done.

Okay. So, it is possible that -- is there any other--?

It's possible.

Any other possible explanation why the hedging would be below market?

I guess I'd just say that the hedging isn't being done below market. So, there is--.

Okay.

I guess I'm saying that you're pretty close in your estimation of why.

Okay. And then the other question I have is just from the drivers for 2011. You mentioned the benefits of the current buyback flowing through. Is that -- is there anything we should read in terms of there on in terms of whether you do an additional buyback or not. Would that just be something you'd update at EEI either way?

Yes, we'll update that at EEI. We have a lot of internal discussion to take place before that time period. We have a Board meeting next week and we'll review all of our financials with them first, but we're not prepared to make any predictions about that at this time.

Okay. Thanks, that's my two.

And we'll take our next question from Jonathan Arnold with Deutsche Bank.

Good morning, guys.

Good morning.

My question also just on hedging. You mentioned that your hedging in the quarter had to do with point of view. Can I -- did it also have something to do with the new EWC structure and the rethink around the whole commercial organization you talked about on the last quarterly call, or is that still a sort of work in progress?

Jon, as far as the hedging goes, it's primarily driven by point of view. As it relates to organizational structure, certainly, the kinds of things we do are what change. So, in large part, your activity, you'll notice a big change as I've mentioned before due to the organizational shift. But it's around the way we approach things, the analytics we have, all of that is going to be improved. But that may help shape our point of view if we get better data than maybe we've had in the past. But certainly it's point of view based.

Okay. Thank you. And then if I could just, on a second topic, you had -- we're looking at the quarterly cash flow statement. There was this estimated losses and reserves inflow of the best part of $300 million. Can you shed some light on to what that might have been?

I'm sorry. Could you say that again?

On the quarterly cash flow statement, the third quarter of 2010, $289 million of inflow from provisions for estimated losses and reserves. Was that something or a collection of items that you could shed some light on to what's in there?

I think that is something I'd have to have Michelle get back to you on. Or Paula rather, I'm sorry.

Okay. Thank you.

And we'll take our next question from Paul Patterson with Glenrock Associates.

Good morning, guys.

Hi, Paul.

Hi. Couple of things. The uprate write-off, what was causing that? And what was the reason for that? I'm sorry if I missed that.

We had planned a -- we had been working on a potential uprate at one of our nonutility nuclear plants, and just with conditions where they are in the markets and things like that. It just isn't something that we think we're going to pursue at this time.

And how much was that, I guess?

I don't know that we disclosed it.

Okay. I was just wondering. It is market-based though?

Pardon me?

It's market based. Is that what it basically -- because the power prices just don't support it?

That's why we didn't do it. It's about $10 million. About $0.03 a share.

Okay. And the longer term outlook and stuff, is that going to be provided at EEI? Is that why we don't see it at this time in the release?

Yes, that's right.

Okay. And just finally, the FERC NOPR for DR, demand response, any thoughts about what we might be seeing in terms of the impact on pricing, if that's approved as it was filed. And I guess as being discussed I guess for full locational marginal price, any thoughts about how that might impact markets or do you see any effect of that potentially happening already or--?

No. I mean I don't think we really have a point of view on that right now.

Okay.

I don't think we do. Sorry.

Okay. Thanks so much.

We will take our next question from Vedula Murti from CDP US.

Good morning.

A couple of things. I apologize if you addressed this, Wayne, in your earlier comments. I came in towards your tail end. One, can you, in terms of strategic initiatives or possibilities, can you talk at all about, any interest you may have in the UniStar situation with EDF and what's going on with the Calvert Cliffs and Constellation, whether it's part of Entergy Nuclear's efforts there. And then I have a second unrelated question.

We're not really going to comment on specific transactions. It's something we're aware of, various things that are going on in the industry. But we need to stick with our historical policy, really not to comment on things of that nature.

All right. And secondarily, can you update us all in terms of -- and again, I apologize if I missed this, in terms of the system agreement, issues with Arkansas and Louisiana and companies wanting to -- leaving the agreement and what types of financial consequences at this point you're seeing?

Gary?

Yes, good morning. When you look at it, what we're preparing for is under the -- where we are today is, is Entergy Arkansas gave their notice and as of December 2013, they would leave the system agreement, as well as Mississippi following up in 2015. We've done several things and the first being is, most recently, we have laid out a structure, Wayne talked about it in his comments called a CODA, which would give us an opportunity to propose some changes. And we're sharing that with each of the regulators. But, they also, for that specific, have a decision to make, whether or not if they're in agreement with it, and if they're not, we would not pursue that.

In addition to that, we have to be prepared for Entergy Arkansas to be in a stand alone position and several things are dealing with that. We're basically in the process of looking at what is actually going to take -- put that into a stand alone condition as we are for Mississippi. And we're looking from a transmission point of view.

There's a couple of activities. One, is where would they get transmission services from and there's some studies that are being done. One is whether or not they join an RTO like SPP, or whether or not they join an RTO like MISO. Part of that study has come out just this week. And Wayne talked about it because we're also looking at it from a system perspective under a FERC study. Which basically has a range of possibilities depending on benefits from negative to positive depending on transmission allocation.

So, pretty much we're pursuing both paths. The first to be -- to give an alternative that preserves the value of a system. And the second then, also to be prepared for Entergy Arkansas and subsequently Entergy Mississippi to leave the system agreement.

And I guess my last follow-up there, if I recall properly, of the operating companies, the one that in terms of the imbalances or the perceived imbalances, the one that benefits the most right now, that would then have to fill in the gap, would be Louisiana. So, is there a possibility then that there would have to be a material cost increase to Louisiana as part of the reshuffle here?

As we look forward to it, I don't see that at this point. But clearly, we've been planning for the system and you see that through the RFP that we've put out as far as assets that we're bringing in to meet those needs as the system changes.

But in a low gas market benefit, it is a little bit different today than it was when there was high imbalances between the systems between Arkansas and Mississippi. So, as long as we continue to see those low gas prices, that imbalance, it is not anywhere near and I think you can see that in the RPC payment this past year was around $41 million from Arkansas as opposed to the $390 million it was the previous year.

Okay, thank you.

Our next question comes from Marc de Croisset with FBR Capital Markets.

Hi, thank you, good morning. Just two very quick questions. The first is very specific on your production cost per megawatt hour. And I see that they've trended up. Is it about 23% quarter to quarter from say 22% to 28% or so. It looks like you're kind of within guidance year-to-date but can you give us any color on what's impacting that?

Leo?

Sure, sure. That's driven by a number of things. Part of it's refueling outage, amortization, part of it's fuel cost and then the production cost would also include that charge that we talked about for the uprate, that flows through O&M as well as the compensation-related expenses.

Great. And quick second question. I didn't see a CapEx schedule in the press release. Maybe I missed it. Is this something that you're updating at EEI? Is it now in a state of flux?

Yes. That's -- we'll be updating that at EEI, the roll forward of the three-year CapEx.

Okay. Thank you very much.

We'll take our next question from Rudy Tolentino with Morgan Stanley.

Hi. I know you've referred to the asset purchases under the 2009 RFP. Can you just give me an update about where those stand and what kind of time line you have for implementing those?

Right now, being in pursuit as far as looking at what deal we can negotiate with the people that respond to that RFP and we would expect probably the latter part of this quarter to really, probably more likely the first part of next quarter to be able to announce those. And then once we do that, then we will go through the regulatory process that comes as a result of that either through interim PPAs and tolling agreements and for ultimate purchase of assets as well as then there's a Nine Mile Stealth Bill that's being pursued. And I think that's like third quarter 2014.

And how long will the regulatory process take once you announce the transaction?

It typically, if you look at it in the past, we have been somewhere between one to two years in that kind of time frame depending on the complexity.

Okay. And then you also -- Jonathan asked about the DWC structures. You mentioned that you're going to do different kinds of things under that structure. Can you just kind of give a little bit more color, of what type of -- what kind of things that you're going to be doing different. Are you going to offer -- you talked about data but are you going to offer different products or expand your services?

Rick, are you on the line? You want to answer that?

Yes. We're looking at all of those different things, Rudy. But, I mean, really, right now, our objective is protect the assets we got. We look at assets that come on the market. And we're always looking out for new assets and we have been, as you can kind of see, in the sold forward table, been offering a little different product in the market with our commodity sales. So, we'll continue to plow that ground over the next 6 to 12 months.

Okay. I guess, I'll look forward to exploring it with you further in a couple of weeks then.

Okay.

All right. Thank you.

Our next question comes from Ashar Khan with Visium Asset Management.

Good morning. Can I just go over -- you said the guidance, for latest of what's happened in the first nine months, the weather was up like $0.55 or so. That would put you above your top end of your range. What were the negative factors, I guess one is the nuclear pricing. But is there other negative factors which have happened in the nine months why you wouldn't be at the top end of the range of surpassing it?

Yes, there is a number of things. There's financing that we've done at the parent versus what we were paying for the revolver. It is kind of a long-term versus short-term decision, in terms of where we would go with that. We also had some of the O&M issues that I talked about that are driving more of a -- some of those are more nonrecurring type of things. The payroll related expenses.

We've got the write-off of the uprate that we talked about. We've had some pressures from pension costs because of discount rates. Those sorts of things that have rolled through as well. So, all of that goes to pushing us again. We're going to -- right now, we would be indicating we're above the midpoint. But not outside the range.

Okay. And then if I can just, based on the data that you've provided, this year, the pricing is going to come up, the factors that you kind of mentioned, the pricing for this year is going to be somewhere in the $59 average on the nuclear and based on hedges that you provided, I guess it is $55. So, what we're looking for is really a $4 detriment. Is that correct? But we will have -- like it will be offset somewhat with an extra terawatt hour of generation. Is that the right way to look at it from the data that you provided?

For next year?

For next year.

Yes. I mean we're going to end up with a little more generation but certainly, the prices -- the market prices have changed. And hence why we've hedged out so much.

Okay. Okay. Thank you.

We'll take our next question from Paul Ridzon with KeyBanc.

Hi, could you just give an update on the PPA discussions in Vermont and where those stand?

Rick?

They're still progressing. And it is a slow process with them. I mean we're -- a lot of terms and conditions that we're going back and forth on. Like I said at some of the investor conferences, I expect that we'll get that wrapped up by the end of the year.

And then could you just -- you had a $0.30 swing at parent. Can you kind of parse out the bigger pieces of that?

Well, the biggest piece of that has to do with taxes and a favorable tax court ruling that we had associated with just in the scheme of how these things play themselves through a 1998 issue.

Can you quantify that?

That's about $0.25

And then just on the 2011 early look, how much was -- how much floating is going to be -- or has been swapped into fix?

I'm sorry. What are you referring to?

Your 2011 early look, you mentioned financing costs, getting out of the revolver. How much notional is that?

We've done $1 billion of term debt.

Is there more coming?

It's possible. We're looking at -- given today's interest rate environment, we're looking at -- again, we did over $900 million at the utilities as well. So we're looking at both the utilities and the parent for more opportunities there.

Thank you very much.

Thank you.

And we have time for one more question. We will take it from Mathew Alias with Green Arrow.

This is actually Tom O'Neill. How are you doing? Just had a quick question for you on the revolver. In the past, that's had limitations on the buyback I think through the debt to cap ratio. And just curious how you're thinking about that, and what limitations you're facing with regard to the debt as you're terming it out?

As far as it relates to the revolver or anything that we would have with covenants, those -- that may or may not be an issue, certainly not an issue at the moment. As far as, the revolver comes due in 2012, we continue to look at what's the right timing and structure for that going forward. As far as it relates to buybacks, it's really more of an overall issue. It's not related specifically to revolver in any way, Tom. It's more related to a combination of business mix, of cash flow production, and credit ratings are all mixed into one. Making sure we have the right liquidity profile, et cetera. So it's not specifically related to the revolver in terms of what we may or may not do with repurchases.

I will say that as it relates to the financing that we've done currently, the longer term financing, we did have some longer term debt that was in place between 2002 and 2005 time frame that matured during the tendency of the spin. And as that matured, rather than replace it, we were looking at a recapitalization coming out of the spin so we didn't take advantage of anything at that point in time. So, really, the -- there was about $1.4 billion of that debt at the parent level at that time. So we've done $1 billion of longer term debt now, I wouldn't necessarily say that it's anything different than where we stood before we started the spin-off process. Not really terming out the revolver. It's just really recapitalizing the way we were already beforehand.

And at this point, we don't have any plans that any incremental debt that we would do at the parent or any more financing that we would do at the parent. We wouldn't intend that currently to be incremental to debt. Again, that's all a function of our liquidity profile, cash flow metrics, what's going on in the nonutility business, and what our credit ratings are. They're all part and parcel to that decision.

Got it. Thank you.

And that concludes our question and answer session. I would like to turn the call back over to our presenters for any additional or closing remarks.

Thank you, operator. 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 5590047. This concludes our call. Thank you.