安特吉 (ETR) 2012 Q2 法說會逐字稿

Good day everyone and welcome to the Entergy Corporation second quarter 2012 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 the Vice President of Investor Relations, Ms. Paula Waters. Please go ahead.

Good morning and thank you for joining us. We will begin this morning with 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 ask no more than two questions.

As part of today's conference call, Entergy Corporation makes certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Additional information concerning these factors is included in the Company's SEC filings. Now I will turn the call over to Wayne.

Thanks, Paula. Good morning everyone. I'll start today with one of our key initiatives -- the proposal for the utility operating companies to join the Midwest Independent Transmission System Operator or MISO. In May, the Louisiana Public Service Commission became the first retail regulator to approve, subject to certain conditions, the proposal by Entergy Louisiana and Entergy Gulf States Louisiana to transfer functional control of their transmission facilities to the MISO regional transmission organization.

MISO change of control proceedings are in various stages of progress before retail regulators in Arkansas, Mississippi, New Orleans and Texas. During the second quarter, the Arkansas Public Service and General Staff modified their position such that Entergy Arkansas should continue to progress toward joining MISO. And when certain conditions are met, the APSC would grant the full change for control.

An order from the Arkansas Public Service Commission could come at any time now. Testimony has been filed in the remaining three jurisdictions, and subject to various conditions, commission staff or the advisors, interveners in each preceding generally have been supportive of, or at least have not expressed opposition to joining MISO, with the exception, of course, of the Southwest Power Pool. We believe we should receive all of the retail commission orders on MISO in 2012.

Given this progress, final preparations are under way now to initiate the regulatory approval process for our proposed spinoff and merger at the Entergy Operating Company's Transmission business with ITC Holdings Corporation. The retail regulatory volumes will describe, on both a qualitative and a quantitative basis, the benefits to customers and other stakeholders resulting from the superior independent model for transmission operations that ITC provides, as well as the improved financial flexibility and strength of the Entergy Utility Operating Company following the completion of the transaction.

We expect to make the initial filings in Louisiana, followed by filings in other retail jurisdictions and at the Federal Energy Regulatory Commission over the next few months. Concurrently, a fully functioning project management office is mapping out the processes, activities and plans for the targeted 2013 closing to ensure a seamless transition.

In other utility developments this quarter, administrative law judges here in the Entergy Texas rate case issued their proposal for a decision in early July. The LJs recommended an overall $16.4 million base rate increase. However, the Staff's working papers that were used by the LJs indicate an approximate $28.3 million retail base rate increase.

Further the ALJs recommended a 9.8% allowed ROE. This compares to the adjusted $105 million base rate increase in ROE of 10.6% that was requested by Entergy Texas. We should note that the recommendation affirmed in full Entergy Texas past fuel costs and made no adjustments to $408 million of capital additions or over 99% of affiliate costs.

That is the ALJs are not saying you are ineffective, inefficient or imprudent. Instead the ALJs' recommendation results from what we believe are misapplications of basic regulatory principles and practices and these misapplications undermine the traditional rate-making process and public policy objectives. The end result makes it impossible for Entergy Texas to earn a fair return, and that is a clear violation of some of the oldest, tested and affirmed principles of regulatory law, no matter how you get there.

In particular, we believe certain adjustments are clearly without basis or merit. For example, approximately $30 million of purchased capacity costs incurred after the end of the test year, but in the allowed pro forma period when those rates will be in effect, was suggested out with a sort of hyper-technical rationale that is at odds with the purpose of the regulation. I won't go through all of the disagreements we had with the ALJs' recommendation, but we strongly believe this is a fundamental misapplication of long-standing regulatory rules and practices in Texas which provide for recovery of known and measurable costs.

Under the ALJs' proposal these nonfuel costs could not be recovered for up to two years, as the time it takes to prepare and complete another rate case that includes the full year of the costs to be reflected in the test year itself. And if the timing isn't perfect between the test year and historical costs, they may never be recovered. That is why it is common practice in Texas and elsewhere to utilize pro forma adjustments for the test year to eliminate discrepancies, particularly when you don't use a formula rate plan or have extensive use of riders.

Regarding regulatory decisions that discourage prudent capacity purchases (inaudible) this will force the development of a robust, efficient wholesale market if it's allowed to stand. A public utility must be afforded the opportunity not only to assure its financial integrity, but it can maintain its credit rating and attract additional capital as needed, but also achieve returns on investment comparable to those of other companies having corresponding risk. This is the law of the land and it is without argument that ALJs' recommendation failed to acknowledge in any way how this proposal lines up against that basic litmus test.

The PUCT is scheduled to take up the proposal for decision at the August 17 meeting. It's expected the final decision will be made at this meeting, or by the next meeting on August 30 at the latest. Entergy Texas has several other remedies available if the PUCT does not reverse the ALJs' recommendation.

Options include continuing to pursue the open rule making docket to establish a rider to recover capacity costs, filing for the authorized transmission and/or distribution of riders to fully recover incremental investment costs above baseline set in a case, preparing to file another base rate case if adequate recovery is not achieved in this proceeding, and of course seeking relief through a legal process.

In Louisiana and New Orleans, annual formula rate plan [fines] were made in May. The Entergy New Orleans 2011 test year AFRP filing reflected earnings below the bottom of the bandwidth, indicating a modest increase in electric and gas rates totaling approximately $4 million. Entergy New Orleans also requested to accelerate funding of its cash storm reserves to allow it to meet the $75 million target by 2017 that was established by the City Council.

Under the FRP tariff, new rates will be effective in the first billing cycle in October. This year's filing follows four straight years of rate decreases in New Orleans. Even with these file changes, electric rates for Entergy New Orleans customers would be nearly 20% below 2011 levels across the country for non-hydroelectric utilities.

Furthermore, rates for New Orleans customers would be among the five lowest in the country after factoring in a reasonable price for CO2 as a proxy for climate risk across the country. The same general profile holds true for the rest of the operating companies, explaining in part the strong economic development activity in our region.

The earned return reflected in the 2011 test year FRP filing for Entergy Gulf States Louisiana was above the bandwidth, indicating a cost of service decrease to $6.5 million. In addition, the Company is requesting adjustments outside the FRP primarily for lower capacity costs.

At Entergy Louisiana the FRP filing reflected 2011 earnings consistent with the bandwidth, and therefore no cost of service adjustments are necessary. While Entergy Texas earned within its bandwidth -- while Entergy Louisiana, I'm sorry, earned within its bandwidth pursuant to the terms of the FRP, the Company is requesting rate adjustments outside of the FRP for capacity costs for PPAs not covered under the [tier] clause.

Both FRP filings with the LPSC are under review now and the FRPs would require rate changes to be effective in September.

In addition, Entergy Louisiana's recent FRP filing was supplemented to include the estimated first year impact of the Waterford 3 generator replacement project. Consistent with the previous LPSC order, rates will be updated upon completion of the project, subject to a standard prudence review. The Waterford 3 project continues to meet revised milestones to achieve the planned end of 2012 in service date.

In early July the steam generators arrived on site. They were ready for installation during the fall refueling outage. This Waterford 3 project is the second major capital project for the nuclear organization this year.

In the spring the extended power outage project was installed at Grand Gulf during its refueling outage that concluded in June. Plant personnel are in the process now of increasing production after achieving the Nuclear Regulatory Commission's approval to operate at the higher power levels of 178 megawatts. This 15% extended power upgrade will make Grand Gulf the largest single-unit nuclear plant of its type in the country.

One last comment relative to generation initiatives. In July, the APSC approved Entergy Arkansas' request to acquire the Hot Spring power plant into a special rider to recover the cost at the 10.2% ROE established in the most recent rate case. This follows the first quarter 2012 certification by the Mississippi Public Service Commission for Entergy Mississippi to acquire the Hinds plant. A separate proceeding on retail cost recovery remains pending in Mississippi.

Closing of the acquisitions has been delayed pending US Department of Justice review. We do not know where the DOJ is with its review of the transaction, or to the extent which its review has been or will be affected by the ongoing civil investigation of competitive issues of utility operating companies. The confidential nature of the DOJ review of the transactions and the civil investigation do not allow me to comment beyond the fact that the reviews are ongoing. However, I can repeat that we believe the Operating Company's practices and policies at issue have satisfied all applicable laws and regulations.

In other utility matters, last month the FERC issued a decision in the Entergy Arkansas opportunity sales case. As a reminder, this case consumes a limited amount of short-term wholesale energy sales less than 0.5% of the total system sales to third parties from 2000 to 2009.

The FERC found that the sales in question were allowed under the system agreement and made and priced in good faith, but disagreed with after-the-fact accounting used to allocate the energy to supply those sales. We believe our actions were consistent with the system agreement and as such have filed for a re-hearing last week. The FERC also set for a hearing a separate proceeding to determine a reallocation of cost among the operating companies consistent with its decision without completing the voluminous necessary calculations, and therefore cannot quantify the effects of the reallocation on individual operating companies at this time.

We may not have a final FERC decision on this matter until 2014.

At Entergy Wholesale Commodities, the NRC renewed Pilgrim's operating license through 2032 in late May, about two weeks before the original license was scheduled to expire. Petition by the NRC came after an extensive and rigorous review spanning a 76-month period where the NRC spent more than 20,000 hours conducting inspections and reviews and soliciting active stakeholder participation. The stated goal of the NRC is to complete these reviews in 30 months.

While the Pilgrim license and renewal was the longest to date, it is almost certain to be surpassed by the Indian Point process given the number of issues and parties involved. We filed the twenty-year license renewal application for Indian Point Units 2 and 3 in April 2007. The application date was more than five years before the expiration of the current operating licenses in September 2013 for Indian Point 2 and December 2015 for Unit 3, and as such, meets the standard for the NRC's timely renewal provision which allows continued operation until the NRC takes action on the application.

Current progress certainly points to timely renewal protection being applied for Indian Point 2 next year and likely for Indian Point 3 as well. Since 2007, (inaudible) issued the required safety value valuation report in 2009, and a supplemental environmental impact statement about a year later in 2010. Both these safety and environmental reports support issuance of the twenty-year license renewal.

Supplements to these two reports are to be expected, as deregulatory guidance comes through the NSC's ongoing oversight as well as when open issues are resolved. Safety report was first supplemented in August of last year and another supplement is expected to be finalized by year-end. Around that time we're expecting to finalize the first supplement to the environmental report.

We do not expect any of these supplements to change the NRC staff's conclusions that there are no safety or environmental issues which would preclude the Indian Point units from operating safely for another 20 years. The next milestone in the NRC process is the initial hearings before the Atomic Safety and Licensing Board scheduled to begin in October.

To date, the ASLB has submitted a total of 16 contentions, the most ever in a license renewal proceeding. And the ASLB is on track to hear possibly three to four times more contentions that have ever been heard in a license renewal proceeding.

New contentions have been resolved; one in a settlement, the other in a commission order. 10 of the 14 remaining contentions are slated for the Track 1 hearing this fall. No final schedule has been set for the remaining 4 issues.

The NRC process allows for additional contentions to be filed after issuance of these supplemental reports or after any new material information comes to light, and as we have experienced the Pilgrim and Vermont Yankee, new contentions may be filed even after the record is closed. I won't go over all the details of each contention. That would, well, take more time than you've got here today. But suffice it to say these are complicated technical issues that take time to fully investigate, resolve and document.

The key takeaway from all of this discussion is that the nature of the rigorous process before the NRC indicates that it will be years until we reach final decision before the commission. In conjunction with the NRC process, we also need resolution on the water quality certification issue associated with the Clean Water Act and the Coastal Zone Management Act consistency determination.

On the first issue, last year we filed notice with the NRC that the New York State Department of Environmental Conservation, or DEC, had not issued a final decision on our water quality certification application within the one-year time period that is required by law. The NRC has not ruled on our filing, but if they agree that a waiver has occurred then a new water quality certification is not a requirement for the NRC's issuance of Indian Point's renewed licenses. In any event, however, Indian Point must comply with New York water quality standards through the proceeding on the State Pollutant Discharge Elimination System permit, or SPDES.

The department's ALJs have combined the water quality certification and SPDES issues into one joint proceeding and are hearing that case in parallel with the NRC review of the waiver issue. Hearings before the ALJs of the New York State DEC will resume this week regarding the best usage of the Hudson River and on the efficacy or performance of the wedgewire screening proposal that we have made.

These are just two of several issues in the water permitting and certification proceedings, but the central issue is the evaluation of what is the best technology available or BTA -- operations with cooling towers or operations with our proposed wedgewire screen alternatives. And either of these options is required only if Indian Point is creating an adverse environmental impact, a point on which we obviously disagree with the state and that we have preserved for further litigation at a later date.

Portions of these proceedings date back to 2003 when the New York State DEC issued a draft SPDES permit for post license renewal periods, suggesting cooling towers are BTA. Since then, we filed expert testimony on how cooling towers don't meet the BTA standards for a host of reasons, including it is highly unlikely that cooling towers can even gain the required air permits or approval by local governments due to zoning and other permitting issues.

And furthermore, it is difficult to see how cooling towers could pass any reasonable cost-benefit test compared to wedgewire screens, which the US Supreme Court has ruled can be considered as an element of determining the best technology available. Staff of the New York DEC has not yet filed its primary report or the basis for why they regard cooling towers as BTA. And no dates for hearing have been set for this threshold BTA issue to be argued in the sunshine before the assigned judges. As it stands today, we would expect these water quality decisions to extend into at least 2013 and possibly well beyond that.

One last issue to report on water -- report, the first (inaudible) under the law on water quality issues is whether Indian Point's operation has an environmental impact on the Hudson River. While the ALJs declined to hear this argument in this proceeding, it is fully supported by our research and evidence and ready to be presented on appeal, to truly [inaudible] somehow prevail in the joint water quality proceedings.

Secondly, and I know all of this starts to blend together over time as you hear this, but this is new and it is certainly not trivial. So you might want to listen carefully. Last week we filed with the NRC a supplement to the Indian Point license renewal application related to the State of New York's requirement for a coastal zone management consistency determination under the federal Coastal Zone Management Act or CZMA.

The supplement states that federal regulations make clear, given previous reviews of the Indian Point facilities, there is no need for a further state CZM review. And as a result, the NRC may issue the requested Indian Point renewed operating licenses without the need for an additional consistency review.

Let me amplify that point. Hang on just a second. I lost about 10 pages of my script here.

Let me amplify that point, the preamble to the federal regulations implementing the CZMA state, in the event the state agency has previously reviewed a license or permit activity, further review is limited to cases where the activity will be modified substantially, causing new coastal zone effects. That exception does not apply in the case of Indian Point since no change in operations is proposed for purposes of license renewal.

Prior CZMA consistency reviews were done for Unit 3 and Unit 2 in 2000 and 2001 respectively, when the New York Power Authority and ConEd transferred ownership of the plants to Entergy. In both instances, the State of New York determined that operation of the Indian Point facilities was consistent with the state's coastal zone management plan. Based upon these and other prior reviews, and the fact that it is part of a license renewal proceedings, Indian Point's continued operations will not be substantially different than when the prior reviews were conducted, we do not believe CZMA requires Indian Point to obtain another consistency review from the state of New York in connection with its license renewal applications.

To that end, yesterday we filed with the ASLB a motion for declaratory order agreeing with our position. Responses by parties including the State of New York to our ASLB motion are due within 10 days, although extensions are possible. We expect that once the parties have stated their positions, the ASLB will set a process, resolve the issue and issue a decision. ASLB decisions are appealable to the commissioners, but if not appealed, the decisions are final.

In summary, we have made clear our position, supported by the expert opinion regarding the law and the consistency of prior reviews conducted on Indian Point, that there is no basis to require CZM determination as part of the license renewal process. How and when the processes will advance from here will be determined by the ASLB. It's important to keep in mind, under federal regulations the NRC is the ultimate decision maker on whether changes have been made that warrant additional review.

As a reminder, the federal law also states that as national policy the preference for continuing to use already developed areas, again like the Indian Point facilities, instead of developing new greenfield areas within coastal zones. Furthermore, New York State's federally approved coastal management program sites, the location of nuclear facilities in the coastal zone including Indian Point has demonstrated the state's recognition of the national interest of energy facilities.

Regarding that last point, there is good reason why Indian Point serves the national interest. Indian Point is safe, secure and viable. It is the only plant in the country to voluntarily submit to an extensive blue-ribbon panel audit, which it passed with flying colors in 2008. The conclusion of the panel of experts was unequivocal. Indian Point is a safe plant.

Before closing I want to highlight a few recent awards recognizing the operational strength of our organization. In a report issued by JD Power and Associates earlier this month, all of Entergy's Utility Operating Companies showed gains in the 2012 Electric Utility Residential Customer Satisfaction Study. In fact, Entergy New Orleans was named the most improved utility company. This contrasts to the results overall, where the National Customer Satisfaction Index declined by 3 points -- the second consecutive year of decline.

A key factor for the industry of course was a negative impact on perception of power quality and reliability due in part to severe storms that affected several parts of the country. In May, nuclear operations once again received top industry practice awards from the Nuclear Energy Institute for innovative improvements in cost and safety practices at Pilgrim and Arkansas Nuclear 1. This is the 10th consecutive year we received nuclear honors in the NEI TIP's award program.

And finally I'm pleased to report that once again Entergy scored a perfect 10.0 global rating from Governance Metrics International in July 2012 for best-in-class corporate governance. Entergy has maintained this rating in each of the quarterly periods since 2006, with the exception of one small dip in early 2011. Establishing stringent corporate governance standards and living up to them every day in everything we do is an absolute necessity to us, and to maintain the trust that you have placed in us.

We demand it of ourselves and I can assure you the Board of Directors demands it in not only of us, but of themselves as well. Now I will turn the call over to Leo.

Thank you, Wayne, and good morning everyone. In my remarks today I will cover second quarter 2012 financial results, our cash performance for the quarter and then add a few closing remarks.

Starting with our financial results on slide 2, higher overall second-quarter 2012 earnings were driven by higher results at both the utility and EWC compared to a year ago, and lower results at parent and other. Second-quarter earnings included a special item for expenses incurred in connection with the proposed spinoff and merger of Entergy's Transmission business with ITC Holdings. Spending on our spin/merge initiative reduced the quarter's earnings per share by $0.05 at the utility.

Now let's turn to operational results for the quarter. Slide 3 summarizes the major drivers for operational earnings. Utility results were higher than a year ago, due primarily to a reduction in income tax expense. This was partially offset by lower net revenue and higher non-fuel operation and maintenance expenses.

In agreement with the IRS regarding storm cost financings in Louisiana for Hurricanes Katrina and Rita, reduced income tax expense by $180 million for the affected companies, Entergy Louisiana and Entergy Gulf States Louisiana. The Company has also recorded regulatory charges totaling $101 million after-tax to reflect an agreement to share the tax benefits with Louisiana customers. The net effect of these items increased utility earnings by $0.44 per share.

Excluding the regulatory charge, utility net revenue was modestly higher this quarter compared to a year ago. The increase was due largely to positive weather adjusted sales growth. After excluding the effects of weather, billed retail sales increased 4%. The Entergy region benefited from a reasonably healthy economy.

Industrial sales continued to grow from expansions. However, overall weather-adjusted sales growth through the second quarter was roughly consistent with what we expected. While the effect of weather was positive for the quarter, it was lower than the significantly warmer than normal temperatures last year. On a year-to-date basis the weather effect was negative and well below last year.

Higher non-fuel operation and maintenance expense partially offset the earnings increase. O&M for the quarter reflected higher compensation and benefits costs, driven primarily by pension expense. Fossil and distribution spending also increased over last year due in part to increased fossil outage spending, with timing differences also contributing to both.

Slide 4 summarizes EWC's operational adjusted EBITDA for the second quarters of the current and previous years. The quarter-over-quarter decline was due primarily to lower net revenue and increase non-fuel operation and maintenance expense. EWC's net revenue reflected lower energy pricing towards nuclear fleet.

Nuclear generation also declined as a result of additional refueling and unplanned outage days, though production was offset by the exercise of re-supply options under power purchase contracts.

The non-nuclear portfolio partially offset lower net revenue from EWC's nuclear fleet. The RISEC plant acquired last December was the driving factor.

Higher non-fuel operation and maintenance expense also contributed to the decrease in operational adjusted EBITDA. The increase was due primarily to higher compensation and benefits costs, again primarily pensions. The RISEC acquisition also contributed to higher non-fuel O&M.

While EWC's operational adjusted EBITDA declined, its earnings increased quarter over quarter. The increase was due primarily to two items not included in adjusted EBITDA -- lower decommissioning expense and a lower effective income tax rate.

Operational results at the parent and other disclosure segment declined due primarily to higher income tax expenses on parent and other activities. The income tax expense increase reflected the net effect of favorable tax items recorded in both quarters. The 2011 effect exceeded the current quarter.

Slide 5 provides a recap of our cash flow performance for the quarter. Operating cash flow for the current quarter was $587 million, or $67 million lower than the same quarter last year. The decrease was due to lower net revenue at EWC and the regulatory refund to a wholesale customer at the utility.

Slide 6 summarizes our 2012 earnings guidance, which ranges from $3.49 to $4.29 per share on an as-reported basis, and $4.85 to $5.65 per share on an operational basis. The as-reported earnings guidance range was updated to include specials recorded in the current quarter. The as-reported guidance does not reflect any potential future expenses for the special item in connection with the proposed spin/merge of Entergy's Transmission business. As-reported earnings guidance will be updated to reflect the special item as actual costs are incurred throughout 2012.

On our last earnings call we identified several challenges that had developed during the first quarter. At that time, we also had other significant uncertainties such as the pending appeal of the foreign tax credit decision. While we still have our biggest quarter to go, as we sit here today we are well-positioned relative to our full-year guidance range. Current indications point to the higher end of the range.

As we head into the second half of the year, we remain focused on continuing to produce positive financial results as well as strong operational performance. And we remain focused beyond 2012 as well. As we look ahead to 2013, I want to offer some initial thoughts.

Turning to slide 7, at the utility we work to get the right regulatory constructs in place to provide every jurisdiction the opportunity to earn its allowed return. One example is the Texas rate case that Wayne discussed earlier, which will have a bearing on 2013 and beyond.

We also have other upcoming rate cases. Entergy Louisiana and Entergy Gulf States Louisiana will file rate cases in January of next year. Entergy Arkansas is also expected to have a rate case tied to its exit from the system agreement at year-end. All are likely to take next most of next year to complete.

Further, the timing and execution of our investment program will affect results. At EWC one of the most significant variables is the price of power, both energy and capacity. Commodity markets continue to challenge margins. However, fundamental indicators in the natural gas market such as narrowing storage surpluses, falling rig counts and low liquids margins appear to be signaling that we are moving off of a bottom and into more constructive territory.

The appendix to this webcast presentation includes details on the current state of the market for energy and capacity prices for EWC.

Protecting the long-term value of our nuclear assets is a key priority. That includes managing the license renewal process for the Indian Point units as well as defending the license renewals already received from the NRC. In the meantime we're utilizing hedging strategies to protect near term value while retaining longer-term options.

For both businesses, managing costs remains at the forefront. However, as we've seen this year, some things like pension expense are driven by external factors we do not control. Efforts are underway to determine opportunities to mitigate cost pressures now and over the long term.

At the parent, we're always looking for opportunities to improve business results. For example, last week we received authorization to execute a $500 million commercial paper program at the parent. The CP program will provide a cost-effective source of capital as well as incremental financial flexibility.

At current rates, borrowing from the commercial paper market would be about 100 basis points below the rate on the revolver, which will provide interest savings and bottom-line earnings. We're now finalizing plans to implement this program in the third quarter, assuming market conditions stay favorable.

Every day we focus on safety, operational excellence, risk management and disciplined capital deployment. Whether managing the current year or planning ahead, the goal is to deliver results that will create tangible long-term value for our stakeholders. And now the Entergy team is available for your questions.

(Operator Instructions) Steve Fleishman, Bank of America.

Hi, good morning everyone. I guess on the last earnings call, Wayne, you brought up the concept of looking at strategic options for the unregulated generation business. Could you just update us on any -- that process there?

I will let -- Leo and his team have been working on this. But I think one of the things that we kind of emphasized that, given the uncertainty in a lot of these marketplaces and the environmental regulations and other types of things, that we almost have to go back. One of the additional things we're doing is going back to when we have tried to form a nexus.

And our opinion at the time, you know, of course it was these businesses don't belong together for a number of reasons. They're financed differently. They have different credit metrics, things of that nature.

And -- but then as power prices have fallen and things of that nature, then credit metrics and credit quality, they become a real issue for this on a standalone basis as it is structured for the wholesale business and -- but nonetheless, we still believe it should be separated from the utility. So, one of the other options is to look at transactions or assets or whatever that impact positively credit quality, so we can get back to maybe the notion of separating the two businesses. But rather than just focus on a functional adding power, maybe it's something else. I will let Leo kind of explain his thoughts on the idea.

Yes, Steve, the bottom line is if you go all the way back to the kinds of things we would have been looking at, at the time we came up with the separation concept, a lot of those ideas haven't gone away. As we have always looked at that portfolio, ways to grow the business, ways to protect the business, way to enhance the credit quality of the business, ways to provide liquidity of the business -- we continue to look at all of those kinds of opportunities, whether they involve internal moves or transactions-based ideas. And really could run the gambit of ways to improve the credit quality, improve the margins, improve the valuation and to make sure that we continue to protect not only the parent company, but the utilities as well.

Okay, one other question, just -- Leo, thank you for giving some of those 2013 drivers and beyond. Is there just maybe kind of a punch line of what you're trying to highlight with these? These seem generally the stuff that we normally kind of -- you have highlighted in the past. Was there any -- is it mainly these rate cases that --?

Well, really, Steve, it's just to give you all an indication of what is going to drive 2013 and beyond and the timing of when those things actually show up during the year, as much as anything else.

Okay, great. Thanks. I will stop at my allowed two.

Dan Eggers, Credit Suisse.

I just wonder if we could go back to kind of the MISO conversation and the ITC transaction. If you think about timing and then kind of perpetual delays to getting the filings done for ITC, is there something structurally you are seeing that is slowing down that process? And what is the level of confidence we will see a filing get done in the third quarter?

Theo Bunting is really heading that process up as the COO of our utility. But I don't think there's anything structurally that's holding it up. Our commitment is to put on the strongest possible case in an area that is kind of new to a lot of the parties to the case, and we want to make sure that we fully support and emphasize how important this is.

We're bringing together two companies, Entergy and ITC, along with a number of outside experts who believe very strongly and have evidence to support why the independent model is so much better than how we're doing it today. And just bringing all of those different points of view and testimony together, so it's clearly everybody is on the same page. And it's clear to the commission and other interveners in the case -- has been a little more challenging probably than we might have expected.

We thought that we would be able to make our first filing in Louisiana near the end of this month. We gave ourselves kind of another week to button everything up and we're just not quite there yet.

Now Leo and Theo are having meetings this week to try to resolve any issues that we feel like are not supported as well as we want, to get that an analysis and the testimony so it reads typically the way we would do it or ITC would do it when you're just doing it on your own. So it's nothing structural. It is just complicated when you involve more parties and we want to get it right. Theo, do you have anything to add?

Yes, I would like to add something. I agree with a lot of -- most all the things Wayne said. The other thing I think you need to consider is we're doing this in multiple jurisdictions. And we're trying to do this in a manner that would allow us to make those filings in those jurisdictions with not much passage of time between filing.

So, obviously we have to think about how do we ensure we incorporate all of the items we need to consider relative to those jurisdictions, so that when we start that process, we don't get any significant slowdown. I do think, as Wayne said, there still some things we need to work through. We will be working through those things over the next few weeks and we'll begin that filing process.

Great, thank you. And I guess, Leo, on the tax issues for the year, is there anything else we should be looking at that you could provide a benefit for this year? And did you anticipate this level of benefit showing up in the guidance when you guys updated it this spring?

Well, when we updated the guidance this year, obviously we had the possibility of both positive and negative items in the tax arena. We knew we were working obviously on a settlement. But at the same point in time we had the appeal of the foreign tax credit decision, which had already been lost in a different jurisdiction at a different district for which we had provided a reserve last year. So that could've been the positive that you saw this quarter because of the win, but if we had lost that case it was a significantly larger negative possibility.

So we had indications around both of those things, but they were unknown at the time and could've gone in either direction. But there is always a few things in the hopper, as you know, based on the size and number of the positions that we've got in front of us at the moment that may or may not turn out, may or may not happen. It could go to litigation like the foreign tax credit case or could be settled; just depends on where you are in the audit cycle and what issues are available there.

We had taken some of that into consideration when we set the guidance, remember the $0.22. I think we characterized that as other. In the improvement in the original guidance, some of that was taken into consideration -- tax items that may or may not occur. I think we even mentioned that at the time.

Okay, thank you guys.

Greg Gordon, ISI Group.

I'm focusing on table 4 on page 3. Your weather-adjusted sales growth has been quite robust. You make some comments in here about the growth -- industrial sales growth, particularly in Louisiana. You also had retail sales growth.

Can you extrapolate, A, on what is going on in terms of residential growth -- why that is so strong, what types of industrial activity you are seeing that are leading to this type of growth? And then the decline in the refineries, could we characterize that as seasonal because, as I understand it, they were down for maintenance? And therefore that should be additive when they come back? It is really a very positive underlying theme here.

Okay, Theo, do you want to take that?

Sure, Greg, as Leo mentioned in his opening comments, obviously on the residential -- start with the residential side first, we are seeing some impacts from still a fairly strong economy in our region, especially when you compare it to what is going on nationally.

Also I think you have to think about some of the things we had last year that didn't necessarily repeat themselves this year. We had certain events last year that had a dampening effect on sales, for instance the flooding we had up on the Mississippi River that reduced sales volumes.

And also I think last year we had fairly extended periods of extreme weather, high bills, and generally customers respond to that. We probably had some amount of customer response relative to bills last year.

And also I think Leo mentioned the fact that --- may have mentioned the fact that our billing cycles this year for the quarter had a few days beyond what we would have seen last year as well. And all of those things really cobbled together had some effect on the year-over-year change.

And if you go back and if you look at the residential growth year over year last year, it was actually slightly negative. So, given that, we saw fairly robust change year-over-year. But again, as Leo said earlier, I think we still fundamentally feel like we're about where we expected to be at this point in time relative to sales.

In terms of industrials, I think it is the chemicals that continue to show fairly strongly in terms of segments in the second quarter. And a lot of that is relative to facilities expansions. As we go through the year, we will likely see some of that moderate as we're kind of seeing those expansions and when they hit in various points and times in prior years.

There are -- obviously we do get outages in certain areas in terms of customers bringing their facilities down for various reasons. And that can move our industrial sales up and down as you compare period to period.

Okay, thank you.

Julien Dumoulin-Smith, UBS.

On the Texas rate case here, if things don't turn out as positively with the final reg here in August, what are the various avenues? You kind of alluded to them quickly on the opening statements, but if we were to see a move towards a capacity type rider, when would that happen? Or alternatively, if we weren't, at what point down the line say six months, a year from now, do we see another filing, just to be a little bit more explicit about the timeline?

Okay, Theo.

It sounded like you had a number of questions there, Julien. I'm trying to feel through them. I guess the first thing I would make sure we well understand is where we're at today is, we basically have a kind of a proposal for decision. It is not an order from the commission and that is still forthcoming.

And part of that, obviously what we would do relative to that would have a lot to do with what comes out of that commission order. I would say it's not unusual in Texas for the commission to not accept all aspects of a PFD. And as Wayne talked about earlier, in terms of various riders that are in place today in the current rate construct in Texas, obviously those would be opportunities for us given -- once we know the outcome of the case itself.

And obviously to talk about what we might do and when we might do it at this point in time is probably a little premature, because we don't have the outcome on the case yet. The capacity rider is -- it's in a rule-making phase. And we are working and will continue to work to move that along.

Also as Wayne mentioned in his opening script, a big part of what the issue in the case as it relates to the recommendation of the ALJs is capacity. And if in fact -- just assuming for a second that we don't fundamentally get what we believe is appropriate treatment relative to that, then we would obviously write to and try to ensure that we move that rule-making along in order to get proper alignment of the regulatory construct in Texas with what we fundamentally believe is appropriate and what is taking place there.

I think, like Theo said, we need to get the order out of the commission; hopefully it will undo some of these -- what we think are inappropriate adjustments. But it won't just be the outcome. It will be the tone set in the order.

Hopefully it will give us some guidance that will be instructive to which way to best proceed. Obviously we don't want to start a war with the commission by going one way if they would prefer another. We are hopeful that they will acknowledge that this does not give us the opportunity to earn a fair return and they will fix that, or give us strong guidance on how to fix that ourselves.

Great. Thank you very much.

Paul Patterson, Glenrock Associates.

Greg asked my question on sales growth. I was wondering, though, on the -- one of the commissioners in Louisiana is talking about changing the ROE kind of significantly on the downward side. And I was wondering if you could sort of elaborate, if he's being joined by anybody else or if he's kind of an outlier on that, and any thoughts you have on that?

Theo may be closer to it. But as you know, in this interest rate environment, I'd suspect there isn't a commissioner in the country you don't have at least one commissioner who is bringing the issue up, is it appropriate. It's a good question.

Obviously interest rates are much lower than what we're used to. And the -- in Louisiana specifically, we really have not heard a lot on the issue. We do have one commissioner a little more outspoken on it. But again that's fairly common I think across the country. But Theo, why don't you --

Yes, I think also one thing that you will note in Louisiana. That issue has come before the commission at least on maybe one, couple of occasions, and they have just not moved it along. As Wayne said, I think we have one commissioner there who is very interested in looking into this.

But I think you also have to consider and I think they have to consider, interest rates is really just one input into that entire process of defining what is an appropriate ROE. You also have to think about risk premiums and you also have to think about the fact that there is a legal standard around what is the appropriate ROE. And that ROE basically should be set such that you can maintain financial integrity of the Company, you can raise capital on reasonable terms, such that a utility can discharge its public duty relative to customers.

And in this period of time where we're seeing fairly extensive capital investment across the utility industry, and I think regulators really need to think about and consider all of these elements as you think about what is the appropriate ROE for a utility.

Okay, great. And on the stock buybacks -- repurchases, any thoughts sort of at this point in time? I know you've got a lot of things going on, a lot of initiatives, obviously the ITC stuff and everything else. How should we think about your thoughts about stock repurchases, given everything that you are looking at and what have you?

Well, obviously we haven't -- didn't have any stock repurchases in the quarter. We have completed $150 million of the $500 million of authority that we have at the moment, so there's $350 million left. Just philosophically, the way the repurchase program works is based on the results out of EWC and/or any kind of transactional-based results that we have.

For example, we sold an asset or what have you, the dividend is usually paid for by the utility, so that is the construct around it. And depending on what capital expenditures are, the cash flow may or may not be used for that. So for example, at the end of last year, when we acquired the RISEC plant --- we spent over $300 million on that plant -- that is part of what goes into the decision-making process around the repurchase.

So, I guess at the moment, we haven't done any recently. We typically don't signal what we are or aren't going to do. But just philosophically to know that transactions and/or EWC nonutility earnings, that is where the buyback money comes from.

Okay, thanks a lot.

Stephen Byrd, Morgan Stanley.

You've been making progress at the state level in moving towards membership in MISO. And in the filings obviously comes up the discussion of distinguishing between MISO membership and approving the ITC sale. Can you talk about just general feedback that you've been receiving at the state level to the ITC sale element relative to MISO, appreciating that that is a later element, but just nonetheless, just any color on the feedback you received at the state level?

Theo, why don't you go ahead and take that.

Stephen, I'm not sure I was -- the audible level was fairly low. Let me see if I can repeat your question on what you were asking. What you are asking as to, in the MISO proceedings, are we getting questions around the ITC sale and/or --- I mean, I just want to make sure I understand what your question was.

Yes, I think my focus really was just on -- in your conversations about the overall ITC transaction at the state level, which understandably would come up as part of the MISO proceedings, can you just talk generally to the feedback that you have been receiving at the state level relating to the ITC transaction?

Yes, and I made a huge mistake. I said sales. It's not a sale; it's a spin/merge. And I hope I don't -- I don't think I used that term in my testimony that I plan to file, but in any case.

It does come up from time to time. But we try to make sure folks understand that they are separate processes. They're separate transactions. They're separate steps.

Obviously we need to get to MISO to an RTO in order to effectuate the IPC transaction. And as we have said to many of the regulators, we are focused on getting to MISO, getting to an RTO. And that is part of the reason I think why you have seen some passage of time and some separation as it relates to the filings around the ITC transaction, is that we are trying to work through within the various jurisdictions that MISO process and move the various commissions along and other parties to get through that MISO process and get our MISO approvals. But it does come up from time to time.

Yes, I think the discussions that I've been involved in, I think it's actually been very encouraging. The regulators have been very interested in trying to understand more. When we proposed similar -- actually I guess it wasn't all that similar a few years ago, it was a hostile environment with regard to some type of divestiture of the transmission system.

The questions we have gotten have been very much on point with regard to how things will change. The overall feeling seems to be that, given the amount of merchant capacity we have in our territory, given some of the feedback that they have gotten from some of the merchants and some of the extensive audits that we have had relative to merchants, some of the merchants' concerns and other concerns, they understand that this needs some sort of resolution other than continuing to try to just regulate this thing to death.

Separating it resolves all of those issues, and eliminates any perception along with -- it solves a lot of problems for Entergy with regard to credit quality and that just lowers rates for customers and ensures reliability. And we've had really good dialogue, I think, with the commissions.

And the biggest concern that I have heard is to try to explain exactly how giving up jurisdiction -- the FERC would have ultimate authority on how they maintain authority to execute their job, ensuring reliability at a fair price and all those types of things, and they don't want to end up just as another intervener at FERC. So that has kind of been working through the process trying to make sure that doesn't happen has been really the issue with them. But again, it has been very constructive.

Great, thank you very much.

Michael Lapides, Goldman Sachs.

I just want to make sure I am following the rate changes you expect between now and maybe the year end of 2013, kind of following on some of Leo's comments. You discussed the Texas rate case. I guess the question is, do you think you would file another case and have new rates in place before year-end '13?

Then the Louisiana formula rate plan adjustments that are outlined in the appendices, do you expect incremental adjustments before the actual Louisiana rating changes or rate cases kind of resolve? And then the timing of an Arkansas case -- how early would you file? When do you think rates would go into effect there? And apologies, a fourth item, how do we think about how Grand Gulf's up rate will impact rates?

Well, I think Theo is getting a good introduction here to his new job. But like we've said before, he's certainly up to the challenge; probably the most knowledgeable person we've ever had in this job. So we're going to let him prove it right now.

I think he is asked me to prove that because first he wants to make sure if I can actually remember all of the questions. (laughter)

I will start maybe in reverse order. Grand Gulf, I think as you may know, Grand Gulf is FERC regulated and there is a specific tariff around how cost through the unit power purchase agreement of SERI and the various operating companies, how that cost flows from Grand Gulf or from SERI to the operating companies. And the various operating companies have different regulatory mechanisms in place to recover cost associated with those billings from SERI. And they vary a little bit jurisdiction to jurisdiction, but they all have fairly timely mechanisms in place to recover cost associated with Grand Gulf.

In terms of filings, obviously we would expect the filing an Arkansas consistent with its departure from a system agreement. And obviously that is targeted for the end of 2013.

Louisiana, when you talked about FRP's, Wayne talked a little bit about the FRP results as it related to our filings based on the 2011 test year. I think as Leo mentioned, we would be making rate case filings in Louisiana in January 2013 to basically reset rates.

Depending upon the length of the proceedings, potentially you could have some impact from that decision relative to that case in 2013. But that will be a function of the procedural schedule that obviously we will get once we make those particular filings.

As it relates to -- I don't remember what other questions you had. Mississippi we made in our FRP filing; no changes relative to that filing based on, again, a 2011 test year. And was there another jurisdiction? Was there a jurisdiction I missed?

When would you -- if Texas rate case resolved in the next month or so, when do you expect you would be back in filing for a new place rate increase?

I think it is premature to talk about that at this point. We don't have an order out of Texas, and so until we get an order and realistically see where we are, we will evaluate that and make an assessment as to when is the appropriate time to file.

Okay, thank you guys. Much appreciated.

And at this time we have no further time for any other questions. I would like to turn the call back over to our speakers for any closing or final remarks.

Thank you Deanna, 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 is recorded and can be accessed on our website or by dialing 719-457-0820, replay code 866-6645.

The recording will be available as soon as practical after the transcript is filed with the US Securities and Exchange Commission due to filing requirements associated with the proposed spinoff and merger of Entergy's Transmission business with ITC Holdings Corp. The telephone replay will be available through August 7, 2012. This concludes our call. Thank you.

Again this does conclude today's conference. We thank you for your participation. You may now disconnect.