安特吉 (ETR) 2012 Q1 法說會逐字稿

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 would like to turn the call over to the Vice President of Investor Relations, Miss Paula Waters. Please go ahead.

Good morning. 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.

Good morning, everyone. The theme of our 2011 annual report to stakeholders is adapting to a changing world. Given the schedules involved for design and illustration, each year we must select our theme four to five months in advance of production and distribution. As it turns out, the selection now looks like we had foreknowledge of what was to come.

It would be, except in Philosophy 101 you learn two things on day one. 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 have been communicating to you our plans and initiatives to address risks or uncertainties, and given our strengths and limitations to adapt to the coming realities that we are now facing. Today I will update you on where we stand and will provide the context for our accomplishments and our challenges.

Starting with one of our key utility initiatives, (technical difficulty) 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 provisions 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 a tariff waiver to implement this same proposal. However, 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 the wrong procedural vehicle to implement the proposal.

In the April 19 ruling on the merits, FERC found 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 shown to 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 plant, including Arkansas Electric Cooperative Corporation, one of the interveners in the FERC proceeding. The settlement regards how the plants 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. Aligned 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 five-year transition period after the Entergy utilities join MISO. This arrangement is designed to address concerns expressed by our regulators.

FERC's recent decision on transmission cost allocations, along with the additional authority to add projects to help address the stated concerns by MISO and provide a wider path for the receipt and necessary regulatory approvals and for a seamless and successful integration and the realization of up to $1.4 billion of projected net customer savings over 10 years. These projected customer benefits derive from joining an RTO with substantial scale and 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. A Day 2 market brings about efficiencies by using one central unit commitment and dispatch based on the economics of transmission and generation of 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 costs of $17 million if the Entergy and Cleco regions joined SPP instead. At the retail jurisdictions and testimony filed in March in Louisiana, all parties except SPP conditionally 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 the 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 an RTO is critical to our transaction with ITC Holdings to completely separate Entergy transmissions business through a spin-off 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 focus.

Over the past three 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 have said before, we fully intend for those filings to further explain our view that spinning off and merging our transmission business with an independent transmission company of 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 risk. 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 two.

On balance, we will ask regulators to consider the net benefits of the transaction. On the one hand, gaining an independent transmission company in a footprint, where even without de-regulation the merchant capacity is almost half the size of the regulated capacity in the region and whose sole focus is transmission. Versus, on the other hand, a change in jurisdiction as a result of the spin/merge.

Initiation and processes related to other key approvals will follow. The target to close the 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. He 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 is 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 has had broad-based experience ranging from strategic and financial planning, regulatory strategy and risk management, to operational support areas including customer service. He was the obvious choice.

Next, I will briefly recap some other developments. In Mississippi the annual formula rate plan filing was made in March for the 2011 test-year period. The evaluation report reflected an earned 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 and Entergy Gulf States Louisiana's application for the Ninemile fixed project on March 21. As you will 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 to be built on an existing Entergy Louisiana site. With regulatory approvals in hand, Entergy Louisiana issued full notice to proceed on the 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 had received a civil investigative demand by the US 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 have provided to the DOJ demonstrates that our practices and policies have been appropriate and consistent with regulatory orders and industry practices.

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 Springs and Hinds transaction. Obviously we don't think it should, but you should be aware of that possibility.

Also at the utility, I am proud to report that once again for the 14th consecutive year, Entergy was recognized with 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 tame season, but of course it only takes one. Should a severe storm strike, we will be prepared as always.

At Entergy Wholesale Commodities, the Vermont Yankee nuclear plant entered the period of extended operation under its renewed Nuclear Regulatory Commission 20-year license on March 22. Three days before that, rulings by the Federal District and the Vermont Public Service Board provided the clarity we had 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 the Vermont Public Service Board in their order to resume the proceeding in a new docket.

Vermont Yankee's continued operations supports us through employment, taxes, and other sources of government revenue to Vermont, which together with the multiplier effect, offered substantial economic benefits to the state. Continued operation also provided for a potential sharing of revenues, offering value and 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 timeline. Concurrently, (inaudible) and Vermont's appeal of the January District Court decision to the Second Circuit Court of Appeals in New York are likely to extend through most of 2012, assuming each party takes its maximum allotted time. As said, the decision is not expected until well into 2013.

At Pilgrim, just a few days ago the NRC staff issued a memorandum asking the NRC Commissions to authorize issuance of the Pilgrim renewed license. A response was requested of the commissioners on their recommendation by May 8. Staff 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 before 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 commission has requested a decision from the ASLB on admissibility of new late contention by no later than May 29. That said, the state may wait until that date before taking any action. With the licensing 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 proceeding is extended past June 8. We continue to believe none of the items identified should preclude 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 have 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 a goal of closing Indian Point. That is 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 1,000 workers in the state of New York.

Indian Point's continued operation is essential to achieving environmental sustainability, affordable energy, and long-term reliability electric systems. Those benefits were described and quantified in last summer's independent Charles River Associates report prepared for New York City's Environmental Protection Department.

In other developments regarding Indian Point, the US Court of Appeals for the Federal Circuit issued a decision on damage claims against the US 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 at various stages of planning or litigation. While we had a number of tactical and strategic successes during the quarter, financial results were negatively impacted by a number of items, resulting in a 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 non-cash 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 of the past two years. To put it in perspective, the southern region had the third-warmest first quarter in 118 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 -- third- and sixth-warmest, respectively.

In the context of long-term valuation, credit cannot be given for the highs and lows, of course, of weather. But nevertheless, the bottom line is we are out $32 million of cash after-tax due to the weather. Another fact 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 over estimated and we later received updated information on other pension assumptions.

Finally, the two charges for the Vermont Yankee impairment and the regulatory asset write-off our non-cash in nature. In the case of the regulatory asset, customer rates were unaffected by the change -- by the charge, I am sorry. Rather, we had an asset recorded on our financial books under 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. The impairment test, as the accounts refer to it, is a valuation that has been consistently performed and disclosed by us since the state actions necessitated it 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, its accounting valuation requires consideration of all potential outcomes resulting in a value that is discounted for the legal uncertainties. This impairment reflects the result at March 31 of applying the accounting rules applicable to VY, utilizing our best judgment and a consultation with our external accounting advisers who have also been involved in other past accounting valuations.

This chart does not reflect the change and interesting point of view on the legal and state regulatory proceedings, nor on the accounting value of the plant based upon our point of view assuming it operates for another 20 years. In any event, we could try to excuse the accounting issues as basically non-cash or nonrecurring, but it's our job to deliver the results you expect and clearly we didn't.

That does not mean we have given up or thrown in the towel on 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 continuing to fall and gas inventories overflowing, as well as a full agenda of regulatory and legal challenges at the utility and EWC, it sometimes seems the 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 transactions 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 other 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 are close to examining options to manage through this down cycle and at the same time prepare the business to capitalize on the options when 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 at 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 flexibility, agility, and greater options. 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 two summarizes first-quarter as recorded in operational earnings results and slide three outlines the major factors that drove the quarter-on-quarter results. First, I will cover the two special items for the quarter. These two 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 spin-off 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 and 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 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 shut down Vermont Yankee early and has been evaluated for impairment under the accounting rules every quarter since the first quarter of 2010.

The accounting rules call for a two-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 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 where 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 two of the analysis, which compared the book value of the assets to the fair value as of March 31, 2012. Fair value is using discounted cash flows.

Because the fair value of the plant was less than the book value, an impairment charge of $356 million pretax, or $1.26 per share after tax, was recorded to reflect the fair value of the plan. The write down represented approximately 70% of the book value of the assets and was allocated pro rate between plants, construction work in progress, fuel, and deferred refueling outage costs.

While accounting details helped to understand the actual impairment entry, there are a few points that I would like to emphasize. To repeat a key point Wayne made earlier, the impairment does not reflect a 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 three 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 would like to note primarily on the accounting aspect 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 accounting treatment of certain income tax items, primarily those associated with pension expense.

In the regulatory construct there are two methods for determining how much income tax expense are included in 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 assets for future recovery of income tax expenses that were already being recovered in rates.

The normalized method has been appropriately applied to the income taxes associated with pension expense and rate making. As a result, this adjustment has no impact on customer rates. The disconnect was in our financial accounting assumption, and the non-cash write-off aligns 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 costs. We noted on our fourth-quarter call in January that pension expense would be higher than planned due to a lower discount rate as well as other updated pension assumptions.

The 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 four summarizes EWC's operational adjusted EBITDA for the quarter of the current and previous year. This quarter's operational adjusted EBITDA declined due primarily to lower net revenue and increased non-fuel operation and maintenance expense. EWC's net revenue decrease 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. The increased generation from the nuclear fleet also contributed to the decline in net revenue. Billed sales were down less than 1% with slightly higher planned and unplanned outage days.

Lower net revenue from the nuclear portfolio was partially offset by increased net revenue from the non-nuclear assets, largely due to the RISEC plant acquired in late 2011. Higher non-fuel operation and maintenance expenses also contributed to the decrease in adjusted EBITDA. The increase was primarily due to higher compensation and benefits expenses which includes pension expenses.

Before we leave EWC, I would like to mention one item in our earnings release. Starting this quarter we have expanded the sold forward table to include details for EWC's non-nuclear plants. The additional information will provide details on the energy and capacities sold, as well as expected net revenue for that portfolio at a point in time. Parent and other operational results declined due to several individually insignificant items.

Side five 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 six summarizes our 2012 operational earnings guidance, which we recently updated to $4.85, $5.65 per share. Several items were in 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 write-off 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 effect 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 nonfuel 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 this special item as actual costs are incurred throughout 2012.

Before we close, I will provide some details on our recently completed credit facilities. On March 9 we completed new five-year credit facilities totaling $4.15 billion for the parent company and four of the operating companies. Pricing terms for the parent facility are LIBOR plus 175 basis points drawn and 27.5 basis points undrawn. These rates increase 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 turns 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 optimal performance from our assets.

License renewal and legal efforts to ensure our ability to run our nuclear plants through an extended license period is also a priority. We also work to effectively communicate and demonstrate that our plants are safe, secure, and beneficial to the communities they serve. We look for ways to provide benefits to our customers and sound investments that include safety and reliability and improved efficiency.

We also focus on risk management to understand the risks in our business, such as the declining commodity price environment that we have 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, an independent transco, will benefit customers and other stakeholders with improvements in financial flexibility, operational excellence, and 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. 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 the near-term issues; it simply means that they are near term.

EWC is obviously a different story with today's price environment and all of 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 risk, 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) Paul Patterson, Glenrock Associates.

Good morning. 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. I can't recall a transaction in which it took that long between the announcement and the actual filings to take place.

I was just wondering if you could elaborate a little bit more on what is going on there and how your conversations are going on with the regulators.

I am going to let Gary Taylor, since this is his last call, get a chance here.

Thanks, Wayne, I think. Actually it has 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 follow that up as there was more clarity with the transmission program to ITC. And that is what we have done.

So, if you look at the timing, we want to make sure that all the hearings were done. They have all been scheduled and clearly those will be completed this summer with a ruling from each of the commissions on an RTO.

The second part was that we wanted to also ensure that many of the commissions have 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 addressed the concerns that they had.

With that we are on schedule to do that, as Wayne had said, to meet our goal of both transition to the RTO by December 2013 as well as supporting the closing of the deal with ITC by the middle of 2013 as well. So very much has been consistent. As far as our regulators, in general they have been very open, very objective, and I think what the staff has seen is a very logical way to address it.

I will just add one thing to that. Gary made a good point yesterday in that -- I know you have all -- many of you have talked to the regulators. You have heard statements by the regulators.

If you go back to MISO, where we were at in that process, and we are well down the road on MISO now, but the ITC we are basically where we were on MISO at this point in time. With the regulators taking a wait-and-see approach, waiting to hear the testimony, waiting to see exactly how we are going to address some of these issues. That is their job.

On MISO, once the numbers were put on the table and they could see what the trade was then it has been very positive ever since. So maybe it appears a little slow coming out of the box, but we expect that once we make the filing that things will pick up pretty fast.

Okay. Just in terms of the flexibility of the transaction, if one of the states -- I mean you are dealing with a variety of states there. If one of the states pulls out, I mean just simply says no or objects, I guess is a better way to put it.

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.

Okay.

I was going to give him all the questions today just as a surprise.

I am surprised.

Leo, you want to take that?

Sure, sure. Paul, that is just not a place that we are going to go. We anticipate that we're going to get -- make the same case in every jurisdiction in terms of the benefits and that we'll get this done across the board.

Certainly there's considerations about the structure we've picked and the transaction that we've struck. So it's not just a regulatory approval of a rate case or something like that where we have got a lot of flexibility around our structuring of this. We have a transaction to preserve and a structure of that transaction to preserve, so there is really nothing I can comment on there.

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

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

Okay, thanks a lot. I will let someone else ask questions.

Leslie Rich, JPMorgan.

Leo, could I ask you to walk through slide seven again, the ongoing impact on Vermont Yankee? I am not by clear I understand what all those different categories are.

Well, the categories have to do with the items that are part of the plant balance from an accounting point of view. There is the plant itself, and that is the one that you can look at from a depreciation standpoint. That is the value of the plant on the books that is depreciated every year.

Since we took the impairment for a portion of 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 are buying the fuel upfront and you have so much of it that comes out every cycle. You have costs associated with the fueling outage get amortized over a period of time. Those are shorter lived assets.

So you allocate the impairment across the asset group of the fuel, the deferred outage costs, and the plant balance. Then those will be ongoing as long as those -- you know, what you have 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 for the remainder of the life.

Okay. That is another 20 years because you have the NRC extension?

Correct, correct.

Thank you.

Julien Dumoulin-Smith, UBS.

Good morning. Can you hear me? Excellent.

I would be curious to get your perspective, you mentioned it briefly earlier on the RFI in New York state regarding 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 alluded to clearly it's sort of an initial look at potentially moving forward with these projects. Finally, what is your expectation of the outcome here? Clearly transmission and power upgrades being considered. So I will leave it to you guys.

It's an excellent question. Certainly one that Rick, who has actually moved up to New York and is very involved in, 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 will let Rick kind of summarize where we come out on that one.

Okay, Julian, I mean as you think about the Energy Highway objective, I mean it's everything that we think makes good sense for long-term utility planning. And I think you start with that.

They are looking at -- they have a lot of generation up north, north of state, west of state that isn't fully utilized. A lot of wind generation out west. What they are 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. They are also looking at the long-term reliability of the electric system.

And, as most states do in the Northeast, they have a pretty aggressive policy around renewable generation and how that could be developed. So I think as it relates to need, there is plenty of excess generation in the north and west, and so that will drive a lot of transmission projects.

Makes a lot of sense also from -- it's a little bit the intent of what the governor laid out, create more jobs. So you are going to build a lot of transmissions with their nuclear -- their renewable portfolio out west looking at more sustainable, environmentally-friendly generation.

But two things that we think they have laid out as part of their intent is also the maximized rate pair value, adhere to market rules and procedures, and maintain the overall reliability of the system. 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, Public Service Commission itself, Indian Point satisfies all those objectives very well.

As it relates to timing, any time you are -- I mean they are going through an RFI process. They just had another meeting about a week ago I think it was and there is an expression of interest or supposed to be filed by the end of May. 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 would issue -- and it won't be the task force. It'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 is 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. Then you eventually get to real projects, probably a couple of years down the road.

I think a lot of them probably will be transmission. So I think as the timing it's going to take a couple of years to play out and I think the outcome will be more transmission and generation. I think there is enough generation in the state; it's just not all in the optimum places.

Rick could expand on it or even Mark could expand on that issue. From a reliability standpoint, even though over the years we have developed -- the industry has developed a number of devices that can help, there is no replacement for local generation that is as good if you are talking about reliability. You can have all the energy, all the capacity, and when you are pushing it down wires, no matter how big they are, how many devices you put on them, local generation is absolutely critical to maintain reliability.

This -- you are talking about 2,000 megawatts optimally positioned in New York. 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.

Great. I appreciate the detail there. 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 regards to pushing more of that off the revolver into long-term financing? Is it baked into your 2012? Is it another 2012 issuance or are we talking 2013 and beyond at this point?

Maybe, more structurally, are you looking to associate 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 spin-off 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 revolver to term or anything like that.

As it relates to transactions, when we look at the majority of the transactions that we have got teed 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. In the ITC transaction, when you think about the financing that we will do associated with that separation, it will be to alter the balance sheets to their right size of the operating companies themselves. So from a transactional standpoint of anything that we have got out there right now that is all related to the operating companies.

I think the -- all other things being equal, the parent company has got the right mix of facility and term debt right now.

Great, thank you very much for the time today.

Thank you.

Steve Fleishman, Bank of America.

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

It's speculation and it's just speculating on logic, in terms of you have one agency with two things in front of them. People sometimes tend to not want to let go of one until they see the outcome of the other. We don't know that. All I am trying to do is bring up the issue of we don't know really what is going on at DOJ and whether they would somehow relate the two.

We don't think they are 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 one agency with two different things they are working on for one company.

Okay. Then just secondly on the New York is there any schedule on the ruling on the water treatment issues at Indian Point? Any update on the hearings for that, the wedge wire, the cooling towers?

Go ahead, Chuck.

Steve, this is Chuck Barlow. 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.

Okay, thank you very much.

Michael Lapides, Goldman Sachs.

First of all, Gary, we will miss you. Please keep in touch and good luck in all your future endeavors.

Thank you.

Wayne, you made comments about the market cycles for power generation and how things are tough now and they are likely going to be tough for a couple of years but they are not going to be tough forever. I also think about your Company's 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 hundred bucks a 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? 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 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. We don't see that certainly happening again for really any asset class.

Probably the most certain thing when you look at it is environment regulations are going to get tougher. Now probably not nearly as tough as the EPA has outlined, which is just a point of view that is going to work its way -- will be played out in probably the courts over a period of 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 is a lot of opportunity because we have a number of companies that are feeling the pressure of these low prices and they are looking to reduce the risk that they warehouse with these assets. We do have the advantage of having really clean, well-located plants, and so I think there is opportunities available without getting into any particular details.

But to work with some of the other companies who have merchant capacity and fleets to develop a more robust kind of portfolio that would -- rather than bet on any one particular kind of future. I know it's not being very specific, but we are spending a lot of time on this and there is 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. I mean you have to -- it's not like one thing you are betting on. There is just a lot of different issues that could swing it 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?

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 may 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 has been sitting in front of the FERC for a while, just kind of sitting there.

Yes. Yes, you are right. Everybody has done their filings and stuff. They are going to have to make a decision; then we will see where that goes after that. But they must be pretty busy with other things.

Understood. Thank you, guys. Much appreciated.

Dan Eggers, Credit Suisse.

Good morning, guys. I guess just kind of thinking about the ITC transaction and as you guys have had the 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 to 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?

Like 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. Maybe that is 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 have been inundated with complaints. We have had various investigations and various requests for data and oversights, and we have processes to address all those issues.

Every single one of them we always come up that we are doing things exactly right according to the rules and all of that, but there is always that suspicion that because you are in the business that you are 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.

In the trading business oversight only goes so far. Separation of duties is everything. For the Commission the oversight with all this merchant capacity is so onerous and it never settles the question. And so by separating the businesses it ends any concerns that anybody has that there is anything going on here that is not in the best interest of everybody or [consistent with the law.

They have heard that over and over again from all the merchants and all the different parties. Just the independents alone is what stakeholders want, that is what we are giving them. Then at the same time there is -- we still think there is enormous upside of having a focus on that business.

I think the main thing that we are emphasizing to them is what the stakeholders want is independence. In these hearings they have tended to agree with the stakeholders that independents would be good and that is -- now they have the opportunity to achieve that.

Okay, thank you. 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 is not going to be any more variation? We should assume a normalized tax rate, is that fair?

Yes. You are talking about the Gulf states?

Yes, yes.

Yes.

Okay, so we will model it that way. Thank you, guys. Have a great day.

At this time I would 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 Regulation G compliance statements.

Our call was recorded and can be accessed on our website or by dialing 719-457-0820. Replay code 4034210. The recording will be available as soon as practical after the transcript is filed with the US 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.