Entergy Corporation (ETR) Q1 2012 Earnings Report, Transcript and Summary

Good day everyone, and welcome to the Entergy Corporation First Quarter 2012 Earnings Release Conference Call. Today's call is being recorded. At this time, for introductions and opening comments, I'd 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'll begin this morning with comments from Entergy's Chairman and CEO, Wayne Leonard; and then Leo Denault, our CFO, will review results. [Operator Instructions] 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'll turn the call over to Wayne.

Thanks, Paula. Good morning, everyone. The theme of our 2011 Annual Report to Stakeholders is Adapting to a Changing World. Given the schedules involve for design and illustration, each year, we must select our theme 4 to 5 months in advance of production and distribution. As it turns out, looks like -- so now it looks like we have a foreknowledge of what was to come. It would be except in Philosophy 101, you learn 2 things on day 1. The first is the beginning of all wisdom is to know thyself. The second is the only constant in life is change. For some time, we've been communicating to you our plans and initiatives to address risks or uncertainties, and given our strengths and limitations to adapt to the coming reality that we are now facing. Today, I'll update you on where we stand, and will provide a context for our accomplishments and our challenges. Starting with one of our key utility initiatives, the proposal for each of the utility operating companies to join a regional transmission organization, specifically, the Midwest Independent System Operator, or MISO. Events continue to move us closer to achieving that goal. In a significant development last week, the Federal Energy Regulatory Commission issued its order conditionally accepting MISO's tariff revisions regarding cost allocations for transmission projects upon introduced transition into the MISO RTO. Just to remind you, last September, FERC denied MISO's request for tariff waiver to implement this same proposal. Moreover, FERC noted in its order that it was not making any findings on the merits of the proposal at that time. The request for the tariff waiver was just a wrong procedural vehicle to implement the proposal. In the April 19 ruling on the merits, FERC founded that it was just and reasonable for MISO and its existing transmission owners to agree to establish a transition period to ensure that no entity must bear the cost of transmission facilities from which it has not been showing the benefit, consistent with traditional cost causation principles. Prior to this FERC ruling, on March 16, Entergy Arkansas reached a settlement with its Arkansas co-owners in its coal-generating plants, including Arkansas Electric Cooperative Corporation, one of the intervenors in the FERC proceeding. The settlement will include how the plant will operate after Entergy Arkansas integrates into MISO. This agreement extends the benefits of MISO participation to all co-owner utilities if the Arkansas Public Service Commission approves the Entergy Arkansas' proposal to join MISO. Combined with Entergy Arkansas, these groups represent 80% of all Arkansas electric customers in the state. In addressing other concerns, utilities have agreed to give the Entergy Regional State Committee, upon unanimous vote, the authority to direct the operating companies to add projects within the Entergy region to MISO's transmission expansion plan during the 5-year transition period after the Entergy utilities join MISO. This arrangement is designed to address concerns expressed by regulators. FERC's reason is based on [ph] transmission cost allocations along with the additional authority to add projects to help address the stated concerns on MISO and provide a wider path for the receipt of necessary regulatory approvals and for a seamless and successful integration and realization of up to $1.4 billion to projected net customer savings over 10 years. This projected cost of benefits derived from its joining in RTO with substantial scale in a mature Day 2 market. As you know, Day 2 refers to an RTO that includes day-ahead and real-time energy markets and uses market-based mechanisms to manage congestion. The Day 2 market brings about efficiencies by using 1 central unit commitment and dispatch based on the economics of transmission and generation resources. MISO has one in place today, SPP does not, although it has plans to. Even assuming SPP will get there, further independent third-party analysis has recently undercut the arguments of those who have opposed our proposed move to MISO. In a study prepared by the Charles Rivers Associates for SPP, SPP is the one that commissioned the study, CRA estimates that SPP members would receive $22 million in trade benefits over the 10-year span from 2013 through 2022, as a result of the Entergy and Cleco regions entry into MISO. Not only that, this study projects that those same SPP members would see an increase in net production cost of $17 million if the Entergy and Cleco regions joined SPP instead. At the retail jurisdictions, and testimony filed [ph] in March in Louisiana, all parties, except SPP, conditionally [ph] support, or do not oppose at least, the move to MISO. Hearings are scheduled to begin next week in Louisiana, and at the end of May in Arkansas, with potential decisions coming in at summer. Regulatory proceedings are also underway or will be soon in Mississippi, New Orleans and Texas. Based on the established procedural schedules, or in the case of Texas, a 180-day requirement, we currently anticipate having final decisions on our MISO proposal in all retail jurisdictions by the end of the third quarter or early in the fourth. Of course joining RTO is critical to our transaction with ITC Holdings to completely separate Entergy transmission's business to a spinoff and subsequent merger. Joining MISO is an incremental step in improving our business model. But the ITC transaction is transformational, offering customers and other stakeholders the opportunity to benefit from complete independence, the advantages of scale, and at the same time, greater function. Over the past 3 months, we have continued our outreach efforts in conjunction with ITC to obtain the input and perspective of our regulators and other stakeholders. With the benefit of greater understanding from these discussions, we are preparing to make initial retail regulatory filings beginning around midyear. As I said before, we fully intend for those filings to further explain our view in spinning off and merging our transmission business with an independent transmission company at the caliber of ITC provides a solid platform for the future. There are no perfect solutions to any long-term issues of public policy. There are however, options. Sometimes the idea is simply bold and exciting but the potential for success is a huge leap of faith with enormous risks. Sometimes the idea is simply one whose time has come. The potential and logic are compelling, and success is highly likely. We believe this is clearly the latter of the 2. On balance, we'll ask regulators to consider the net benefit of the transaction. On the one hand, gaining an independent transmission company in a footprint, where even without deregulation, the merged capacity is almost half the size of the regulated capacity in the region and who's sole focus is transmission, versus, on the other hand, a change in jurisdiction as a result of distant [ph] merge. Initiation processes related to other key approvals will follow. The target to close a transaction remains in 2013. Our incoming group President of Utility Operations, Theo Bunting, has been instrumental in developing the regulatory plan we are now executing. Theo will take over the top Utility box on June 1 from Gary Taylor who announced his retirement earlier this year. Gary is on his last earnings call today, which he just reminded me of. And he will certainly be missed. But I know he would tell you that he's turning the Utility over to very capable hands. Theo, who is on the call with us this morning as well, currently serves as Entergy's Senior Vice President and Chief Accounting Officer. In his 20-plus years at Entergy, he had broad-based experience for anything from strategic and financial planning, regulatory strategy and risk management to operational support areas including customer service. He was the obvious choice. Next, I'll review -- briefly recap some other developments. In Mississippi, the annual formula rate plan volume was made in March for the 2011 test year period. The evaluation report reflected an earning return on equity of 10.92% within the performance adjusted bandwidth, therefore, no change in rates. In Louisiana, the Public Service Commission approved Entergy Louisiana, Entergy Gulf States Louisiana's application for the Ninemile 6 project on March 21. As you'll recall earlier this year, the New Orleans City Council authorized Entergy New Orleans' participation. Ninemile 6 is a 550-megawatt new modern state-of-the-art natural gas-fired combined cycle plant we built on the existing Entergy Louisiana site. With regulatory approvals in hand, Entergy Louisiana is with full notice to proceed on its construction of Ninemile 6. The new plant is expected to go in service in the first part of 2015. As you know, we disclosed in the fall of 2010 that we received a civil investigative demand by the U.S. Department of Justice to investigate competitive issues concerning certain generation procurement, dispatch and transmission system practices and policies of the utility operating companies. Due to the confidential nature of this matter, I am limited on what I can say today. All I can say, or more accurately, all they will let me say, is that it remains outstanding. And we believe the documentation we provided to the DOJ demonstrates that our practices and policies have been appropriate and consistent with regulatory orders and industry practice. With respect to our announced acquisitions of the Hinds and Hot Spring facilities, the parties have satisfied their obligations under the Hart-Scott-Rodino Act but the DOJ is still reviewing the transaction. I do not know if the complexities of our discussions with DOJ will affect the timing of DOJ's review of the Hot Spring's and Hinds' transactions. Obviously, we don't think it should, but you should be aware of that possibility. Also at utility, I'm proud to report that once again for the 14th consecutive year, Entergy was recognized with its leadership in storm restoration. This year, we won both Edison Electric Institute's Emergency Recovery and Emergency Assistance Awards. The 2012 hurricane season starts June 1. And happily, predictions call for a contained season, but of course it only takes one. So if a severe storm strikes, we will be prepared as always. At Entergy wholesale commodities, Vermont Yankee nuclear plant entered the period with extended operation under its renewed Nuclear Regulatory Commission 20-year license on March 22. Three days before that, rulings by the Federal District Court and the Vermont Public Service Board provided the clarity we requested that VY would continue to operate while legal and regulatory proceedings are pending. The Vermont Attorney General and the Vermont Department of Public Service have stated their agreement with that, and the Vermont Public Service Board has acknowledged this reality even if they don't agree. On April 16, we filed our amended petition for a Certificate of Public Good for continued operations required by Vermont Public Service Board in their order to resume the proceeding in a new docket. Vermont Yankee's continued operations supports the public good through employment taxes and other sources of government revenue to Vermont, which together with the multiplier effect call for substantial economic benefits to the state. Continued operation also provides for potential sharing of revenues, offering value protection against higher energy prices in the future. The Public Service Board has scheduled a status conference for May 2, which may shed some light on the time line. Concurrently, briefings in Vermont's appeal of the January district court decision to the 2nd Circuit Court of Appeals in New York are likely to extend through most of 2012, assuming this process [ph] takes its maximum amount of time. As said, the decision is not expected until well under 2013. At Pilgrim, just a few days ago, the NRC key staff issued a memorandum asking the NRC commissioners to authorize the issuance of the Pilgrim's renewed license. A response was requested of the commissioners on their recommendation by May 8 that specifically noted that although a new late file contention has been referred to the Atomic Safety and Licensing Board, or ASLB, when an appeal of an ASLB decision is pending upon the commission, the NRC is not compelled to await exhaustion of those appeals before renewing the operating license. This represents an important step. That said though, the commissioner has requested a decision from the ASLB on admissibility of the new late contention by no later than May 29. That said, they may wait until that day before taking any action. With the license expiration date of June 8 just around the corner, we're not there yet. But in any event, the NRC's timely renewal doctrine would apply to allow continued operation if the proceedings extend past June 8. We continue to believe none of the items identified should preclude the issuance of Pilgrim's license renewal through 2032. Regarding Indian Point, NRC and state proceedings related to license renewal remains ongoing. But we know you've been following with interest Governor Cuomo's Energy Highway initiative, which has brought more attention to Indian Point. First of all, this initiative is very preliminary. In the preliminary meetings to date, the State of New York has not expressed the goal of closing Indian Point. It has either good legal advice or good common sense, instead, the New York administration has identified the uncertainty regarding continued operation in light of other proceedings, specifically license renewal and related state water quality proceedings. The continued operation of Indian Point advances New York's stated goals and objectives, and directly provides high value jobs to more than 1000 workers in the State of New York. Indian Point's continued operation is essential to achieving environmental sustainability, affordable energy and long-term reliability of electric systems. Those interests were described and quantified in last summer's independent Charles Rivers Associates report prepared for New York City's Environmental Protection Department. In other developments regarding Indian Point, the U.S. Court of Appeals for the Federal Circuit issued a decision on damage claims against the U.S. Department of Energy for its breach of obligations regarding the spent fuel disposal contract for Indian Point units 1 and 2. Assuming no further appeals are filed, EWC could receive cash payments estimated to be in the range of $100 million in the next several months. For our other nuclear plants, damage claims for DOE's failure to begin disposal of spent fuel in 1998 are in various stages of planning or litigation. While we had a number of tactical and strategic successes during the quarter, financial results are negatively impacted by a number of items, resulting in the decision to reduce our 2012 operational earnings range even though it is still early in the year. In a few minutes, Leo will review the details. As he does, keep in mind that in our view, the underlying issues are either not new or are noncash or in some cases, both. First, financial results in the quarter were negatively impacted by unseasonably mild temperatures this winter, a reversal of the colder than normal weather over the past 2 years. To put it in perspective, the southern region had the third warmest first quarter in 118 [ph] years of record keeping. In fact, Arkansas and Mississippi set a record for the warmest March over that same time period, with Louisiana and Texas not far behind at third and sixth warmest, respectively. In the context of long-term valuation, credit cannot be given for the highest and lowest, of course, of weather. But nevertheless, the bottom line is, we're out $32 million of cash after tax due to the weather. Another factor reflected in our revised 2012 earnings outlook is the impact of historically low interest rates and the termination of pension expense. As we discussed in our last earnings call in January, final pension expense assumptions were different than what we assumed in setting guidance. The discount rate was overestimated, and we later received updated information on other pension assumptions. Finally, the 2 charges for the Vermont Yankee impairment and the regulatory asset writeoff are noncash in nature. In the case of the regulatory asset, customer rates are unaffected by the change -- by the charge, I'm sorry. Rather we had an asset recorded on our financial book on an accounting method that goes back to the Gulf States' acquisition in the mid-90s that was simply overstated. For Vermont Yankee, whatever you believe about the value of the plant, that should not have changed because of the impairment charge. Impairment cash as the accountants refer to it, is a valuation that has been consistently performed and disclosed by use into state actions necessitated in 2010. The ramifications of this low natural gas price environment is not unique to Vermont Yankee but the key for us was whether there has been a triggering event requiring an impairment evaluation as in the case of Vermont Yankee. Due to Vermont Yankee's unique position in the courts, this accounting valuation requires consideration of all potential outcomes resulting in a value that is discounted through a legal uncertainty. This impairment reflects the result at March 31 of the applying the accounting rules applicable to VY, utilizing our best judgment and in consultation with our external accounting advisers who have also been involved in our -- in other past accounting valuations. This chart does not reflect a change in Entergy's point of view on the legal and state regulatory proceedings nor on the economic value of the plant based on our point of view assuming it operates for another 20 years. In any event, we could try to excuse the accounting issue as basically noncash and nonrecurring, but it's our job to deliver results you expect and clearly, we didn't. That does not mean we've given up or thrown in the towel in 2012. We will continue to work to meet or even exceed our original earnings guidance, but the numbers just aren't there right now. With natural gas and power prices continue to fall and gas inventories overflowing as well as the full trend of regulatory and legal challenges at the utility and EWC, it sometimes seeing some news is all negative. It's not. The Board of Directors and management team are focused on adapting to the world as it is, and as it will be, not how we wish it to be. There are ever new challenges but there will be opportunities that come along with those changes. For example, initiatives like the MISO proposal and the ITC spin-merge transaction create real benefits for our customers and other stakeholders and reflect our first rule, know thyself. The structure delivers value we simply cannot do on our own. There are others similar opportunities. Commodity prices have a long history of volatility, with today's bearish natural gas price levels, which are likely to persist in the near-term, we're closely examining our options to manage through this down cycle, and at the same time prepare the business to capitalize on the option that markets improve. But I should be clear about that. While the current low prices do not appear sustainable, the old days of double-digit natural gas prices do not appear to be realistic either. For the economy, for jobs, for the environment, for customers, for sustainable growth, abundant natural gas in moderate prices creates a promising future. And while low prices may not be the best news for Entergy's merchant fleet, we will adapt. This brings me to the second rule, change is constant, but we will continue adapting, not to losing but to new ways of doing business and creating more flexible, flexibility, agility and greater options. And now I will turn the call over to Leo.

Thank you, Wayne, and good morning, everyone. In my remarks today, I will cover first quarter 2012 financial results, our cash performance for the quarter, 2012 earnings guidance and some closing remarks. Slide 2 summarizes first quarter as recorded in operational earnings results, and Slide 3 outlines the major factors that drove the quarter-on-quarter results. First, I'll cover the 2 special items for the quarter. These 2 items are included in As Reported results but are excluded from Operational results. One special item is for expenses incurred in connection with the proposed spinoff and merger of Entergy's transmission business which we announced in December. Spending on our spin-merge initiative reduced earnings per share by $0.04 in the quarter, $0.03 at the Utility and the balance at Parent & Other. The other special item is for an asset impairment recorded at EWC for the Vermont Yankee asset. Under generally accepted accounting principles, long-lived assets are typically accounted for on a historical basis unless a triggering event occurs which results -- requires an impairment evaluation. For Vermont Yankee, the initial triggering event was in early 2010 when the Vermont Senate voted down a bill that would have allowed the Public Service Board to consider VY's application for a Certificate of Public Good. The vote raised questions regarding the operation of the plant through 2032. As a result of this vote and ongoing efforts by the state to shutdown Vermont Yankee early, the plant has been evaluated for impairment under the accounting rules, every quarter since the first quarter of 2010. The accounting rules called for a 2-step process. First, the book value of the asset is compared to an estimate of future undiscounted or nominal net cash flows expected to result from ownership of that asset. If the cash flows are equal to or higher than the book value of the plant, no impairment is indicated and the test is complete. Cash flow estimates consider future operating expenses and future market prices as well as the availability of the asset. The impairment analysis compares the carrying value of the asset to probability weighted expected cash flows measured at the end of each quarterly period. As you might expect, the key driver for cash flow estimates is forward prices. For impairment analysis, we have consistently used observable market prices were available. As you all know, at March 31, those prices declined significantly, which produced a different result this quarter. Because the undiscounted cash flows were less than the book value of the plant, we then performed step 2 of the analysis, which compared the book value of the assets to the fair value as of March 31, 2012. Fair value is typically determined using discounted cash flows. Because the fair value of the plant was less than the book value, an impairment charge of $356 million pre-tax, or $1.26 per share after-tax, was recorded to reflect the fair value of the plant. The write down represented approximately 70% of the book value of the assets and was allocated pro rata between plant, construction work in progress, fuel and deferred refueling outage costs. While accounting details help to understand the actual impairment entry, there are a few points that I'd like to emphasize. To repeat a key point Wayne made earlier, the impairment does not reflect the change in our view of the legal and state regulatory proceedings and the overall economic value of Vermont Yankee assuming we win and operate for 20 more years. Also, the impairment derives from the unique legal and state regulatory processes surrounding Vermont Yankee which make it uncertain that the plant will operate until the license expires in 2032. Absent this uncertainty, the evaluation for impairment would not have been required. The Vermont Yankee impairment naturally raises questions about our other non-utility nuclear plants, however, Vermont Yankee is unique for the reasons I noted earlier. As we sit here today, no triggering event has occurred for any of EWC's other nuclear plants so no evaluation is required or planned. However, even if we had evaluated EWC's other nuclear plants using our current operating assumptions and the March 31 price assumption, an impairment would not have been required. Now let's turn to operational results. Slide 3 summarizes the major drivers for operational earnings. Utility results were lower than a year ago due primarily to higher income tax expense, lower net revenue and higher non-fuel operation and maintenance expense. Utility income tax expense was higher due to a non-cash write-off of a regulatory asset associated with income taxes. I won't repeat the same points that Wayne made in his remarks, but there are a few details that I'd like to note primarily on the accounting aspects of this issue. During the quarter, Entergy Gulf States Louisiana determined that its regulatory asset for income taxes was overstated because of the difference between the regulatory and the accounting treatment of certain income tax items, primarily those associated with pension expense. In the regulatory construct, there are 2 methods for determining how much income tax expense are included in the customer rates, normalization and flow-through. At a very high level, normalization follows GAAP income tax expense, while flow-through follows income tax payment. While normalization is typically the preferred method, some jurisdictions do use flow-through for various items. EGSL's retail rates were developed using the normalization method, but the financial accounting assumed that rates were being set using the flow-through method which had actually been the case prior to the GSU merger. As a result, EGSL's accumulated regulatory asset for future recovery of income tax expenses that were already being recovered in rates. The normalized method has been appropriately applied to income taxes associated with pension expense in rate making. As a result, this adjustment has no impact on customer rates. The disconnect was in our financial accounting assumption and the noncash write-off aligned the regulatory asset with the regulatory treatment. Utility net revenue was lower this quarter than a year ago due largely to unfavorable weather in the current quarter compared to favorable weather last year. As Wayne noted, weather was significantly warmer than normal this quarter. Excluding the effects of weather, retail sales increased 3.3% which was consistent with our expectations. Sales volumes were higher across all customer classes. Industrial sales were up 4.6% as the positive effects of facility expansions continued. Weather adjusted residential sales increased 2.6%. Growth was particularly strong in the Louisiana jurisdictions. Higher non-fuel operation and maintenance expense also contributed to the lower earnings results. Higher O&M was partly due to increased compensation and benefits expenses which was driven by higher benefits cost. We noted on our fourth quarter call in January, the pension expense would be higher than planned due to a lower discount rate as well as other updated pension assumptions. Utility also had higher fossil expenses due partly to the Acadia acquisition which is offset by higher net revenue from the rate action associated with that acquisition. Higher fossil outage expense also contributed to increased O&M, a portion of which is considered timing. Slide 4 summarizes EWC's operational adjusted EBITDA for the quarter, for the quarter of the current and previous year. This quarter's operational adjusted EBITDA declined due primarily to lower net revenue and increased nonfuel operation and maintenance expense. EWC's net revenue decreased compared to the first quarter of last year due to lower energy pricing for its nuclear fleet. Prices were down for both contracted sales as well as power sold at market. The average contracted price was $50 and the average price sold at market was approximately $30. Decreased generation from the nuclear fleet also contributed to the decline in net revenue. Build sales were down less than 1% in slightly higher planned and unplanned outage days. Lower net revenue from the nuclear portfolio was partially offset by an increased net revenue from the non-nuclear assets, largely due to the RISEC plant acquired in late 2011. Higher nonfuel operation and maintenance expenses also contributed to the decrease in adjusted EBITDA. The increase was primarily due to higher compensation and benefits expense which includes pension expenses. Before we leave EWC, I'd like to mention one item in our earnings release. Starting this quarter, we've expanded the sold-forward table to include details for EWC's non-nuclear plants. The Additional Information will provide details on the energy and capacity sold as well as expected net revenue for that portfolio at a point in time. Parent & Other operational results declined due to several individually insignificant items. Slide 5 provides a recap of our cash flow performance for the quarter. Operating cash flow for the current quarter was roughly $600 million, about $280 million higher than the same quarter last year. The increase was due to lower pension funding and lower working capital requirements. These increases were partially offset by lower net revenue. Slide 6 summarizes our 2012 operational earnings guidance which we recently updated to $4.85, $5.65 per share. Several items weren't considered in our revised guidance range, some of which we discussed on our last quarterly call. Pension expense for the year will be higher than planned due to a lower discount rate and other updated assumptions. Market power prices have continued to decline since our original guidance was issued. As of the end of the quarter, average pricing for the unsold nuclear portfolio was $30 for the full-year compared to $46 assumed in guidance. Weather was significantly unfavorable in the current quarter. The regulatory asset writeoff noted earlier also reduced earnings. Operating expenses at VY, specifically fuel, refueling outage, amortization and depreciation will be lower going forward as a result of the asset impairment. The ongoing effect for 2012 is estimated to be $0.14. This affect declines over the next few years due to the effects of the write-down of the shorter-lived fuel and deferred refueling outage assets. Slide 7 provides details on the ongoing effects by category. Opportunities to offset some of the factors that have gone against us so far include reductions in non-fuel operation and maintenance expense, lower than planned interest expense based on financings completed to date, and potential income tax benefits incremental to the original plan. Our updated 2012 As Reported earnings guidance of $3.55 to $4.35 per share includes specials recorded through the first quarter but 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. Before we close, I'll provide some details on our recently completed credit facilities. On March 9, we competed new 5-year credit facilities totaling $4.15 billion for the parent company and 4 of the operating companies. Pricing terms for the parent facility is LIBOR plus 175 basis points drawn and 27.5 basis points undrawn. These rates increased from 2007 levels, but were in line with other recent utility transactions. Circumstances like the spin-merge transaction announced with ITC last fall caused us to delay this financing longer than we otherwise would have. Though not by design or any attempts to time the market, the final terms achieved reflected improved market conditions from the levels a year ago. In February 2011, estimated pricing was at 200 basis points drawn and 30 basis points undrawn. Assuming $1.5 billion drawn, today's terms compared to a year-ago yield, approximately $4 million per year lower cost. Since Hurricane Katrina, we have obtained significant improvements in our liquidity position. At the end of 2004, we had $1.6 billion in credit facilities and negative storm reserves. At the end of the first quarter, we have $4.3 billion in credit facilities, of which $2.8 billion is available. We also have storm reserve escrow accounts in Louisiana, Mississippi and New Orleans, totaling $336 million. These improvements give us confidence that we are prepared to quickly address a wide range of potential events that could affect our liquidity including storms. This is especially important as we move into the summer and hurricane season. As we look ahead, we continue to work to create value for all of our stakeholders by focusing on both operational excellence and portfolio management. For operational excellence, we manage our everyday costs and look for ways to improve efficiency and effectiveness through continuous improvement efforts. All of our employees focus on safety and operational excellence to get optimum performance from our assets. License renewal and legal efforts to ensure our ability to run our nuclear plants during extended license period is also a priority. We also work to effectively communicate and demonstrate that our plants are safe and secure and beneficial to the communities they serve. We look for ways to provide benefits to our customers and sound investments to improve safety and reliability and improve efficiency. We also focus on risk management to understand the risks in our business such as the declining commodity price environment that we've seen over the past few years. And we look for ways to mitigate those risks, such as new hedging strategies consistent with our point of view. On portfolio management, we create meaningful benefits in all of our businesses for our customers and other stakeholders, with initiatives, like the effort to join MISO, which is projected to produce $1.4 billion in savings for our utility customers over a 10-year period. Our proposal to spin off and merge the transmission business with ITC, and independent Transco, will benefit customers and other stakeholders with improvements in financial flexibility, operational excellence in the independent and transparent ITC model. EWC also explores ways to get the most out of its portfolio, such as we did with the RISEC acquisition. We also look for ways to create other opportunities, and we continue to take steps necessary to maintain financial flexibility as reflected in solid credit metrics and strong liquidity. The bottom line is that the utility fundamentals are still strong. Weather-adjusted sales were good, we have a constructive investment program and our strategic initiatives like MISO and ITC, which will benefit our customers and other stakeholders, are progressing. As Wayne said, it doesn't mean we won't work very hard to overcome these near-term issues. It simply means that they are near-term. EWC is obviously a different story, with today's pricing environment and all the political issues. But we are also working to preserve and enhance the value of that option through our regulatory strategy, operating model and market-facing activities. But in both cases, our long-term strategies to manage risks, remain financially solid and rationally grow the businesses remain intact. Our management team is focused on accomplishing the goals we've set out and to move us towards our overarching goal, of creating and delivering sustainable long-term value to all of our stakeholders. And now our senior team is available for your questions.

[Operator Instructions] Our first question comes from Paul Patterson with Glenrock Associates.

Just in terms of the ITC transaction. I guess, listening to ITC and what have you, it sounds like you guys are planning on doing a filing in the retail jurisdictions in the summer of this year, and I can't recall a transaction on which it took that long between the announcement and the actual filings to take place. And I was just wondering if you could elaborate a little bit more on what's going on there, and how your conversations are going on with the regulators.

Okay, I'm going to let Gary Taylor, since this is his last call, get a chance to speak here.

Thanks, Wayne. I think, actually, it's gone as we would have planned. Early on, we talked about the fact that it was very important for our regulators to focus on the RTO transition piece and then file that up as there was more clarity with the transmission program through ITC. And that's what we've done. And so if you look at the timing, we want to make sure that all the hearings were down. And they've all been scheduled, and clearly, those will be completed this summer with the ruling from each of the commissions on an RTO. The second part was that we wanted to also ensure that many of the commissions had ex parte rules, and we wanted to have meaningful conversations with each of them, so when we made the filings this summer, that they were complete and address the concerns that they had. With that, we're on schedule to do that, as Wayne has said, to meet our goal of both the transition to the RTO by December of 2013 as well as supporting the closing of the deal with ITC by the middle of 2013 as well. So very much it's been consistent, and as far as regulators in general, they've been very open and very objective, and I think with what the staff is seeing is a very logical way to address it.

I'll just add one thing. Gary made a good point yesterday in that -- I know you've all, many of you have talked to the regulators, you've heard statements by the regulators, and if you go back to MISO, where we were at in that process, and they were well down the road on MISO now, but the ITC were basically, is where we were on MISO at this point in time. With the regulators taking a wait-and-see approach, waiting to hear the testimonies, waiting to see exactly how we are going to address some of these issues, and that's their job. And on MISO once the numbers were put on the table and they could see what the trade was, then it's been very positive ever since. And so maybe it appears a little slow at someone out of the box, but we expect that once we make the filings, that things will pick up pretty fast.

Okay. And just in terms of the flexibility of the transaction, if one of the states, I mean, you're dealing with a variety of states there, if one of the state pulls out, I mean, just somebody says no, objects, I guess, is better way to put it. I mean, how flexible are you guys in terms of dealing with that, or any potential change? I guess, settlement, what have you, how flexible is the transaction do you think in terms of dealing with that potential situation from developing?

Gary? I was just kidding Gary about that one. I was going to give him all the questions today, just as a sort of surprise.

I'm surprised!

Leo, you want to take that?

Sure, sure. Paul, that's just not a place that we're going to go. We anticipate that we're going to get, make it the same case in every jurisdiction in terms of the benefits and then we'll get this done across the board. Certainly there is considerations about the structure we picked and the transaction that we've struck. So it's not just a regulatory approval of the rate case or something like that where we've got a lot of flexibility around our structuring of this, we have a transaction to preserve and structure that transaction to preserve. So there's really nothing I can comment on there.

Okay. And just the middle of the next year is what we're thinking about still here?

There's been a lot of discussion about that and what we've said is next year. And it would be nice if it was in the middle of the year. That's about as early as you could I think as you could reasonably project it could happen. But we do expect it in next year, but I would hesitate to pick a time period at this point.

Our next question comes from Leslie Rich with JPMorgan.

Leo, could I ask you to walk through Slide 7 again on the ongoing impact from Vermont Yankee? I'm not clear I understand what all those different categories are.

The categories have to do with the items that are part of the plant balance. From an accounting point of view, there's the plant itself and that's the one that you can look at from a depreciation standpoint, that's the value of the plant on the books that's depreciated every year. Since we took the impairment for a portion of the plant balance, that will reduce depreciation expense going forward. The deferred fuel or the fuel outage costs and the fuel itself, also given the way outages work, if you think about it, you were buying the fuel upfront and you have so much of it that comes out every cycle and you have costs associated with the fueling outage, you could amortize over a period of time, those are just shorter-lived assets. So you allocate the impairment across the asset group of the fuel, deferred outage costs and the plant balance, then those would be ongoing as long as those what you've written off you won't have to write off over the period of which those would have been amortized. So the fuel and the outage costs have a short life. The plant, obviously, has a life through the end of the license, so the depreciation expense goes down through the remainder of the life.

Okay, and that's another 20 years because you have the NRC extension?

Correct, correct.

Our next question comes from Julien Dumoulin-Smith with UBS.

I'd be curious to get your perspective, you mentioned it briefly earlier on the RFI on New York State regarding on incremental transmission and power development. Just wanted to get, first your perspective on how these upgrades might change the need ultimately for Indian Point? Secondly, the timing of any such outcomes, again you eluded to clearly sort of an initial look at the potential moving forward of this project? And finally, what is your expectation of the outcome here, clearly transmission and power upgrades being considered? So, I'll leave it to you guys.

That's an excellent question. Certainly one that Rick, who's actually moved out of New York and is very involved in it and John also. And we've been following and been very involved in a lot of the details of what is going on and what is likely to happen. So I'll let Rick kind of summarize where we come out on that one.

Okay, Julien, I mean, as you think about the energy highway objectives, I mean it's everything that we think makes good sense for long-term utility planning. And I think you start with that, they're looking at, they have a lot of generation up North, north of the state, west of the state that isn't fully utilized, a lot of wind generation out West. And what they're looking at is trying to eliminate some of those constraints, and try to give an opportunity of some of that generation serving the lower part of the state. And they are also looking at the long-term reliability, the electric systems, and as most states do in the Northeast, they have a pretty aggressive policy around renewable generation, how that could be developed. So I think as it relates to need, there's plenty of excess generation in the North and the West, and so that will drive a lot of transmission projects. Makes a lot of sense also from a little bit the intent of what the governor laid out, create more jobs. So you're going to build a lot of transmission with a nuclear, I mean, renewable portfolio out West, looking at more sustainable, environmentally friendly generation. But 2 things that we think they've laid out as part of their intent is also to maximize rate payer value, adhere to market rules and procedures, and maintain the overall reliability of the system. And I think that all plays well with the Indian Point unit as has been laid out in the past. Both the New York ISO, the CRA study, the Public Service Commission itself, Indian Point satisfies all those objectives very well. As it relates to timing, anytime you're coming in or their going through an RFI process, they just had another meeting about a week ago I think it was, and their expression of interest are supposed to be filed by the end of May. And then, the task force is looking at potentially identifying some of those requests for interest to maybe take to the next step which would be they'd issue a -- and it won't be the task force that's going to have to be, probably the utilities themselves request for proposals around particular projects. So as it relates to anything like that, that's going to take a while to kind of work through that, work it back through the New York ISO process and the Public Service Commission process, and then you eventually get to real projects probably a couple of years down the road. And I think a lot of them probably will be transmission. So I think as the timing is going to take a couple of years to play out, and I think the outcome will be more transmission than generation. I think there is enough generation in the state, it's just not all in the optimum places.

Yes, all I need is Rick could expand on or even Mark could expand on that issue. From the reliability standpoint even though over the years, we've developed in the industry a number of devices that can help, there is no replacement for local generation, it is just good. If you're talking about reliability, you can have all the energy, all the capacity. And we are pushing it down wires, no matter how big they are, or how many devices you put on them, local generation is absolutely critical to maintain reliability. And these are like 2000 megawatts optimally positioned in New York. And no plan that you are going to come up with is going to produce an expected reliability level as good as one that includes Indian Point. It's just that simple.

Maybe kind of looking a little bit, taking a different direction, more directed towards Leo. I saw the refinancing in the quarter, January obviously taking some more off the revolver. What is the expectation as you stand here today with regard to pushing more of that off to revolver into long-term financing? Is it baked into your '12, is it another '12 issuance or are we talking 2013 and beyond at this point? And maybe more structurally, are you looking to proceed any kind of further refinancing with any kind of transactions of any sort?

As far as the parent company goes, if you go back in time prior to the spinoff announcement, the nature of our term versus liquidity at the parent is pretty much in the same position now as it has been. So I wouldn't expect major changes on that, all other things being equal, in terms of pushing more from the revolver to term or anything like that. As it relates to transactions, when we look at the majority of the transactions that we've got keyed up, for example the power plant acquisitions or even the ITC transactions, those are operating company financings. So if you think about the power plants at a specific jurisdiction, those jurisdictions do their own financing for those power plants. And in the ITC transaction, when you think about the financing that we'll do associated with that separation it will be to a fixed -- to alter the balance sheets to the right size of the operating companies themselves. So from a transactional standpoint of anything that we've got out there right now, that's all related to the operating companies. And I think that all other things being equal, the parent company has got the right mix of the facility term debt right now.

Our next question comes from Steve Fleishman with Bank of America.

Wayne, you kind of mentioned this issue of the DOJ investigation from a couple of years ago and tie it into the Hinds transaction. Is it just the issue that those transactions need to be approved by DOJ so that's how they might end up the getting tied together?

Well, it's speculation. I mean it's just speculating on logic in terms of you have 1 agency with 2 things in front of them. And people sometimes tend to want -- not want to let go of one until they see the outcome of the other. We don't know that. I'm just -- I'm trying to do is to bring up the issue of we don't know really what's going at DOJ, and whether they would somehow relate the two. We don't think they're related. But I want to make you aware of that possibility, that it could get delayed. Not necessarily because they are tied together but because it's 1 agency with 2 different things they're working on for 1 company.

Yes, okay. And then secondly, on New York, is there any schedule on ruling on the water treatment issues at Indian Point? Any update on the hearings for that, the Wedgewire cooling towers?

Yes, go ahead, Chuck.

Yes, Dave, this is Chuck Barlow. There will be -- it will be a relatively slow summer. There will be a couple of wrap-up type hearings on some issues that have already actually been tried. This summer, there is some briefing, post-trial briefing, going on this summer, but the other issues that we have outstanding such as what is actually the technology that will be required, looks like it will definitely go into 2013, as we look at having and wrapping up that trial. So we don't see the likelihood of any incremental decisions being made by the administrative law judges or any final decisions being made on the water quality front before that.

Our next question comes from Michael Lapides with Goldman Sachs.

Wayne, you made comments about the market cycles for power generation, and how things are tough now, and they're likely going to be tough for another couple of years, but they're not going to be tough forever. And I also think about your companies and your leadership history of being what I would call a contrarian buyer, meaning there weren't so many guys who went out and bought nuclear plants at a couple of hundred bucks per kilowatt back in the late '90s, early 2000s. Are there -- when you look at the merchant power markets today, are you seeing opportunities that have the similar value creation potential to the ones you saw in the late '90s, early 2000s around nuclear? And if so, are there specific, either asset classes or markets, that attract you the most?

Well, if I had the benefit of hindsight, I could, 10 years from now, I could tell you which ones will fit that description. When we bought the nuclear, we never expected the prices to be as high as they were for a period of time there. And we don't see that certainly happening again for really any asset class. Probably the most certain thing that when you look at it is environmental regulations are going to get tougher now. Probably not nearly as tough as EPA has outlined, which is just a point of view that is going to work its way and will be played out in probably the courts over the period in time. And there will be assets that people don't view as having much value that will probably have a lot longer life than people think. But I think from our perspective, there's a lot of opportunity because we have a number of companies that are feeling the pressure of these low prices, and they're looking for -- to reduce the risks that they were [ph] out with these assets. And we do have the advantage of having really clean, well located plants. And so, I think there are opportunities available. I wouldn't get in depth to any particular detail, but to work with some of the other companies who have merchant capacity fleets and who develop a more robust kind of portfolio that would rather than bet on any one particular kind of future. I know that's not being very specific, but we're spending a lot of time on this and there's a lot of interest, I can say that, with a number of other companies in terms of trying to figure out how they work their own way through this also. It's a very uncertain time because I mean you have to -- it's not like one thing you're betting on. There's just a lot of different issues that could swing one way or the other.

I would argue all times are like that and it just depends on where you are in the cycle, right? Are there -- would you prefer to add concentration in markets where you already participate in, where you already have physical presence versus expand into other markets?

Yes, absolutely.

Okay. And this one might be one for Rick. Rick, when do you expect rulings in the New York ICAP docket?

We really don't know.

I mean, it seems that it's been sitting in front of the FERC for a while, just kind of sitting there.

Yes, you're right. I mean, everybody has done their filings and stuff. They're going to have to kind of make their own -- they're going to have to make a decision, and we'll see where that goes after that. They must be pretty busy with other things.

And we have time for one additional question, and we'll go to Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: I guess, I was just kind of thinking about the ITC transaction, and as you guys have had a chance to spend some time with the different commissioners and staff members. How are you maybe verbalizing the value proposition of having ITC run the system? Obviously, there is real cost benefit that the MISO involvement as you guys have demonstrated, but with the higher cost of capital and that sort of thing, what value are you guys trying to really sell them on, to get them on board with the deal?

Well, I think I mentioned in the comments, a lot of the advantages. But clearly, the scale they bring and the focus that they bring is unique, and maybe that's a leap of faith that they will find ways to do things that we wouldn't necessarily. But as you know, all of our state regulators have been, ever since the merchants came into our territory in these very large numbers, they've been inundated with complaints and we've had various investigations and various requests for data and oversights and we have processes and to address all those issues and every single one of them, it would always come up that we're doing things exactly right according to the rules and all that. But there's always that suspicion that because you're in the business that you're not. And that somehow, something is being wrong or whatever -- being done wrong. Some of us come from at least partial backgrounds like you all do in the trading business, and in the trading business, oversight only go so far. It's separation of duties is everything. And for the commission, the oversight is with all this merchant capacity is sole owners and it never settles the question. And so, by separating the businesses, any concerns that anybody has that there's anything going on here that's not in the best interest of everybody or consistent with the law, and they've heard that over and over again from all the merchants and all the different parties, and just the independence alone, is what stakeholders want. That's what we're giving them. And then at the same time, we still think there's enormous upside of having focus on that business. And I think the main thing that we are emphasizing to them is what the stakeholders want is independence, and these hearings, they've tended to agree with the stakeholders that independence would be good. And that's -- now, they have the opportunity to achieve that. Dan Eggers - Crédit Suisse AG, Research Division: Okay. And then I guess, Leo, just to make sure I understood, on the tax treatment, the Louisiana income tax reset was unique to this period. So kind of going forward, there's not going to be anymore variation and we should assume a normalized tax rates up there?

Yes. You're talking about the Gulf States? Dan Eggers - Crédit Suisse AG, Research Division: Yes.

Yes.

At this time, I'd like to turn the conference back over to management for any closing remarks.

Thank you, Lauren, 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 Reg G compliance statements. Our call is recorded and can be accessed on our website and by dialing (719) 457-0820, replay code 4034210. The recording will be available as soon as practical, after the transcript is filed with the U.S. Securities and Exchange Commission. The telephone replay will be available through May 3, 2012. This concludes our call. Thank you.

This concludes today's conference. Thank you for your participation.