安特吉 (ETR) 2013 Q2 法說會逐字稿

Good day, everyone. Welcome to the Entergy Corporation second quarter 2013 earnings teleconference. Today's call is being recorded.

At this time, for introductions and opening comments, I would like to turn the call over to the Vice President of Investor Relations, Ms. Paula Waters. Please go ahead.

Good morning, and thank you for joining us. We'll begin today with comments from Entergy's Chairman and CEO, Leo Denault, and then Drew Marsh, 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.

With respect to the planned spin-merge transaction, ITC filed a registration statement with the SEC, registering the offer and sale of shares of ITC common stock to be issued to Entergy shareholders in connection with the proposed transactions and the registration statement was declared effective by the SEC on February 25, 2013. ITC is expected to file a post-effective amendment to the registration statement and ITC shareholders are urged to read the prospectus included in the ITC registration statement. And the post-effective amendment to the ITC registration statement, when available, for important information about TransCo and the proposed transactions.

In addition, on July 24, 2013, our subsidiary Mid South TransCo, LLC, filed a registration statement with the SEC, registering the offer and sale of TransCo common units to be issued to Entergy share holders in connection with the proposed transactions. This registration statement includes a prospectus of TransCo, related to the proposed transactions. Entergy will also file a tender offer statement on Schedule TO with the SEC, related to a planned exchange of shares of Entergy common stock for the TransCo common units.

Entergy shareholders are urged to read the prospective included in the ITC registration statement and the post-effective amendment to the ITC registration statement when available, the TransCo registration statement, the tender offer statement on scheduled TO, when available, and any other relevant documents because they contain important information about ITC, TransCo, and the proposed transactions. These documents and other documents related to the proposed transactions, when they are available, can be available free of charge on the SEC's website at WWW.SEC.gov. The documents, when available, can also be obtained free of charge from Entergy upon written request.

Now I'll turn the call over to Leo.

Thanks, Paula. Good morning, everyone. Last quarter, I laid out the road map for 2013 with seven strategic imperatives we are focused on that will bring sustainable value for our owners, our customers, our employees, and the communities we serve. This morning, I will update you on progress on each imperative over the last three months. As a reference, the seven strategic imperatives are listed on slide 2 to the webcast presentation.

Starting on execute on MISO and ITC. The targeted December 19 cutover date for the Utility operating companies to join the Mid-continent Independent System Operator is approaching quickly. Many operational and regulatory activities are ongoing in parallel to ensure a seamless transition. Last month, we received additional orders from the Federal Energy Regulatory Commission on certain key MISO-related issues. We appreciate the FERC's timely action on the items.

Also in May, on the implementation front, we ran a simulation on processes, situations, and communications that employees will handle when MISO integration is complete. Over 100 participants from Entergy, MISO, and ITC were involved over a two-day period. The exercise did highlight area to work on. More importantly, however, it confirmed we are well on track for accomplishing what would be a step change in how we plan and operate our system.

Regarding the spin-off and merger of the transmission business with ITC, in the second quarter we received key transactions approvals from the FERC and the private letter ruling from the Internal Revenue Service confirming the tax-free nature of the transaction structure. These items come in addition to the April 16 ITC shareholder approval I mentioned last quarter.

This brings us to the retail regulatory approvals. We entered the final critical stages in the second quarter.

After careful consideration of the input from parties in all of the retail proceedings, we and ITC offered a package of rate mitigation and other commitments, including a total of $453 million in rate mitigation over the first five years across all jurisdictions, as detailed on slide 3. And a test to ensure customer benefits exceed ITC's higher return on investment capital before rate mitigation ends. These proposals align the realization of the benefits the transaction offers to customers and the rate effects from ITC's higher cost of capital.

We transfer the risk of achieving the benefits of what we believe is a superior business model from the customer back to the Companies. We are not asking regulators or our customers to make a bet on us. We have been held accountable for delivering benefits exceeding the cost of ITC ownership.

We strongly believe this transaction will more reliable, more efficient grid than joining MISO alone, as I reviewed in detail last quarter. The better grid benefits customers through fewer and shorter outages, reduce congestion and line losses, and greater access to lower cost power. The rate mitigation and other proposals commit us and ITC to delivering both performance and economic benefits that exceed the rate effects on ITC's higher cost of capital. Rate mitigation will continue until they do.

These proposals were developed and offered jointly by us and ITC. We are not in a position to discuss all of the details, but I can offer a few points about how we and ITC plan to allocate the rate mitigation between the two of us.

The Entergy Operating Companies and ITC will share in the $387 million of the wholesale and retail bill credit component of rate mitigation in the first five years. This is the part that is not attributable to forward test periods. The Entergy Operating Companies will bear 65% to 70% of this component. ITC will bear the rest. The Entergy operating components will fund the $40 million of mitigation, associated with the forward test year in the first three years.

The balance of rate mitigation is comprised of net before the costs. For years 6 through 10, if rate mitigation is still required, the Entergy Operating Companies and ITC will split those costs 50%, 50%. After 10 years, the Entergy Operating Companies' obligation will be fixed at a modest amount and ITC will be responsible for any balance required. Finally, the Entergy Operating Companies' responsibility for rate mitigation will end after 20 years.

As I've said before, we believe that the benefits for our customers, employees, and communities are real. This rate mitigation proposals puts us and ITC on the hook to deliver them. We do not shrink from being held accountable.

In the last two weeks, we were encouraged by the coalition of cities in Texas. After consideration our commitments, many of which were directly responsive to their concerns, 14 cities to date have passed resolutions in favor of the transaction. The cities made a filing with the Public Utility Commission of Texas supporting a finding of public interest for the transaction, provided that Entergy Texas, NITC, meets certain conditions.

The PUCT will consider the application at their opening meetings next week on August 9. We are hopeful that the benefits of the transaction including the rate mitigation plan combined with the city's resolution and East Texas Electric Cooperative's recommended support will provide the Texas Commission the basis it needs to approve the application.

We are in various stages in other jurisdictions. Upcoming dates for filings and hearings are on slide 4. Based on current schedules, decisions by all of our retail regulators are anticipated in the fall. We believe in this transaction. We are convinced it is the right approach and the facts and important public policy considerations support its approval by our regulators.

The next strategy imperative listed on slide 2 is to optimize the organization through human capital management. We refer to this effort internally as HCM. In July, we completed a comprehensive review of our organization design and processes. This effort resulted in a new organization structure, designed to provide optimal service to our stakeholders.

This process is a critical part of our ability to be successful at our goals of being efficient, continuing to control our costs, and improving service levels. Other opportunities to make our organization more flexible and adaptable to business changes are under consideration. In the long run, these changes will insure our employees are in the right jobs, have right skills to be successful and the right tools and resources to meet the changing business needs.

Near term, however, workforce reductions are a difficult but necessary step. We have identified approximately 800 positions throughout the Company which we expect largely will be eliminated by year end. In addition, the organizational redesign effort will reduce contractor spending.

Difficult decisions like job reductions are sometimes the result of making long-term fundamental improvements in the way a company works. The redesign process was lead by a team of Entergy employees and had the full involvement and oversight of the entire Executive Leadership Team. In addition to realizing sustainable savings, the teams are tasked with the goals of improving the way we work, placing the right people with the right skills in the right roles. The process is comprehensive, thoughtful, and focused on being fair and responsive to the needs of all of our stakeholders.

While we spent a lot of time on organizational design and process, this past quarter we are evaluating additional opportunities to obtain savings and improving compensation and benefits, procurement, and non-employee operating expenses. As a result of progress to date, we have set a financial goal of $200 million to $250 million in savings to be implemented by the end of 2015 and fully realized by 2016.

I know you have more questions about the savings targets. Drew will cover those details to the extent that they are currently known. As we continue this effort I want to reemphasize safety, security, customer service, reliability, and compliance will never be compromised.

The third strategy imperative is to maintain financial flexibility. Since I introduced this on last quarter's earnings call, many of you have questioned what we mean by this. I want to be clear. We mean simply what it says, maintain financial flexibility.

Today we meet and expect to meet the continue to meet our financial flexibility objectives. Gross liquidity stood at a healthy $4.1 billion on June 30. Our credit ratings are stable at both Moody's and Standard and Poor's. Our current financial outlook which extends through 2014 supports deploying capital and meeting our obligations without the need to issue traditional common equity.

Maintaining alternatives and head room to avoid the damaging effects of dilution on our owners is the central focus for the Board of Directors, me, and the rest of the Executive Leadership Team. This and the other strategy imperatives are simply about being better positioned to pursue more customer and owner focused actions in the future, over and above our current plans and commitments.

The next two strategic imperatives I will talk about are related, growing the Utility business such as through economic development, and continuing to develop and implement productive regulatory constructs. To be successful at one requires attention to the other. For example, effective regulatory constructs can provide utilities with the financial stability needed to make necessary investments and take actions to deliver reliable service to customers, while keeping rates reasonable.

Low rates helps to keep existing businesses competitive and attract new investments to the region. Higher growth can be cycled through the regulatory constructs to spread fixed costs over more volume. Defining and pursuing this path is one of the keys to addressing the risks from so-called disruptive challenges faced by the utility industry.

I'm sure you noticed in table 4 of today's investor news release, quarterly weather-adjusted sales were down in all customer classes. On the residential side, increasing interest in energy efficiency and demand side management are contributing factors, something that we anticipated in 2013 expectations.

On the topic of energy efficiency, New Orleans, Arkansas, and Texas, the jurisdictions where programs are up and running get through a rider or base rates, as well as performance incentives in all three jurisdictions in the recovery of lost contributions to fixed costs, of limited form of recovery in Arkansas and New Orleans. Sluggish economic growth also contributed, affecting all segments.

Industrial sales were disappointing once again this quarter. Near-term factors, such as inventory liquidations and slowing exports, have reduced industrial electricity usage, principally in the small to mid-sized segments in Louisiana, Arkansas, and Mississippi. While near-term challenges exist, new industrial development activity is a bright spot in our future expectation beyond 2015.

Shortly after the last earnings call, Entergy Gulf States Louisiana announced a long-term contract with Cameron LNG to supply an additional 200 megawatts for 10 to 30 years to their proposed LNG facility. Construction is expected to begin next year. This is just one example of the large pipeline of new capital investments for manufacturing and other economic development projects. Our region has an attractive business climate, lead by its access to an abundance of natural resources, reasonable cost of living, including electricity rates, tax and other business reforms enacted at the state and local levels, and programs such as the Comprehensive Workforce Training program in Louisiana.

To update statistics from April, we now have over $50 billion in high probability investment projects in various stages in our service territories. This represents approximately 1,500 megawatts of load and more than 27,000 new jobs of which nearly 11,000 would be direct. Obviously, all of these projects may not happen. We may not supply all of these projects and some may not be completed. The point is this much in the pipeline illustrates the potential for growth for our customers and our communities.

I know I don't have to remind you that we have a number of regulatory proceedings underway in each jurisdiction including rate cases, formula rate plan filings, and storm recovery. I will give you a brief update on major developments. All the usual details are provided in our release and in the webcast slides.

In Mississippi, Entergy Mississippi and the Mississippi Public Utilities staff filed a stipulation settlement to resolve the 2012 test year formula rate plan proceeding. The stipulation called for a $22.3 million annual revenue increase. The rate change provides funds necessary for increased reliability, capacity for economic growth, and the ability for flexible use of the power plants on the grid. It's the first FRP increase in four years, and even after, Entergy's Mississippi rates will be well below a number of utilities in the Southeast and more than 10% below the national average.

The next Mississippi Public Service Commission meeting is scheduled for August 13. If approved, new rates would be effective beginning with the September billings.

In May, the Louisiana Public Service Commission approved a settlement in the proceeding relating to Entergy's Gulf States Louisiana's natural gas operations. The settlement extended the gas rate stabilization plan for an additional three-year term through 2015 test year. The return on equity midpoint was revised to 9.95%, down from 10.5% and the plus or minus 50 basis points range was maintained. This settlement resulted in $678,000 rate increase for customers related to the 2012 test year.

In addition, the LPSC order directed the Company and staff to work toward a gas infrastructure investment rider. The LPSC has a long-standing practice of using formula rate plans and riders for electric and natural gas utilities. Request for new three-year formula rate plans are a component of Entergy Louisiana and Entergy Gulf States Louisiana rate cases filed earlier this year.

Regarding the rate cases, the Entergy Louisiana companies have requested LPSC review of the administrative law judge's denial to consolidate the two rate cases. As part of this request, the companies are seeking a 60-day delay in procedural schedules to allow all parties to explore a framework for a more efficient review of the case request and possible resolution, and set a new procedural schedule should the Louisiana Commission approve the motions to consolidation the two rate cases.

The consolidation matter is on tomorrow's LPSC's business and executive meeting agenda. Given these developments, the [ALJ's] and Entergy Gulf States Louisiana and Entergy Louisiana rate cases suspended the upcoming August deadlines for staff intervener testimony there.

Riders are another construct our regulators approved to support actions to benefit customers and the companies. In early May, the Public Utility Commission of Texas approved a new rule adding a purchase power capacity rider as another tool available for Texas utilities. This rider will be available for Entergy Texas in the future. However, based on a review of the Company's financial status and expectations, Entergy Texas expects to file a base rate case in the third quarter.

Turning to the EWC business for the next strategic imperative listed on slide 2, improving EWC results, we have a number of options we are exploring. On the revenue side, forward energy prices declined in recent weeks. The New York restive state capacity market continues to improve. Second quarter spot auctions cleared near $4.40 per kilowatt-month, roughly 60% higher than first quarter of this year and more than 2.5 times higher than second quarter of last year. Capacity market improvements were driven by the effects of successful mitigation, and in projects with contracts were reflected at fair prices in the auction, and plant retirements in [Teflon].

In addition, a new capacity zone for the Lower Hudson Valley remains on track to begin next summer, subject to FERC approval. A New York independent system operator identified the need for this new zone to address transmission deliverability issues and improve grid reliability. The FERC decision is expected in the near term. Indian Point is located within this new zone where prices are expected to be higher than the rest of the state market where it currently resides.

While we remain encouraged by the progress made related to the Lower Hudson Valley capacity pricing, we remain concerned about some of the overall market design issues in New York and New England. We are committed to continuing to work toward promoting competitive and fair power markets in those regions. From the cost efficiency perspective, EWC completed a reorganization this month, as part of the strategic imperative to improve results, reducing costs going forward. It was handled separately from the human capital management optimization effort due to the financial realities the business is facing.

Reorganization efforts in nuclear operations at the nuclear plants and nuclear headquarters are part of the overall HCM effort. Additional ideas and opportunities for efficiency and productivity improvements to the plants are in various stages of review and implementation. Regarding our nuclear operations, we were pleased to announce a new director in June, Retired Admiral Kirkland Donald. His tremendous experience, including important positions in the Navy's nuclear program, will enhance an already strong oversight by the Board of Directors.

Our actions and success in the final strategy imperative, aligning corporate culture, can be best judged by our results. How well we execute on the other strategic imperatives requires alignment throughout our organization. And successful execution requires a skilled and focused organization, from top to bottom that is designed and managed to perform and achieve.

We recognize there are a lot of complexities to our Company today. That is inherent in the seven strategic imperatives for 2013. It's a busy year for us. We know it is for you, too, tracking the numerous filings, regulatory decisions, and management execution. We are aiming for success in all of our strategic imperatives to support a step change and our customers' value proposition and that of the Company. Next year should provide a clear picture of who we are and where we are headed as a Company.

Next year, we plan to be part of MISO delivering benefits to our customers, estimated at approximately $1.4 billion in the first decade upon integration into the MISO region market. Next year, we will not be working on the ITC transaction. We will remain firmly committed to this transaction because we believe that the ownership of our Midsouth transmission business will create the most value for all our stakeholders if held by ITC. For our customers and community, it will lead to lower delivered energy prices, or employees, better job opportunities in a largely singularly-focused business.

This represents incremental value over and above what the transmission brings to Entergy and its stakeholders today. That said, if the transaction does not close, we will continue to operate efficiently, make economic and reliability investments to optimize to our achieving capital management imperatives, and continue to seek out productive regulatory constructs, and grow the business.

By early next year, the pending rate cases in Arkansas and Louisiana will be resolved. Rate cases are a basic part of our business. We will have two others pending in Texas and New Orleans. But the uncertainty caused by the number of outstanding cases in jurisdictions will be behind us. Nevertheless, we will continue to seek out productive regulatory constructs that reward efficient operations and facilitate access to capital on reasonable terms in order to maintain reasonable rates.

Next year, we will be well into the implementation phases of our human capital management optimization efforts. The new organization design will largely be in place. This is a central component to the effort, but not all of it. Further development of other opportunities continues, some of which will likely also be in implementation stages by then.

We are working to have better clarity before next year on the direction of the EWC business. We are considering a number of avenues and options to adapt to the current business and market realities. While we are working to strengthen the business financially, we also know the plants are valuable to all stakeholders, including employees and communities for the direct and indirect jobs that they provide, to customers and communities for the environmental, reliability, and fuel-diversity benefits from their operations, and to owners for the option for power price recovery they represent.

As we consider strategic alternatives for EWC, all options are on the table. Our focus today is on streamlining for 2014 and beyond for all stakeholders by aligning our organizational designs, functions, and processes, where owners reducing complexity makes us an easier company to follow, predict, and value. For employees, redesigning our organization to be more efficient and aligning our corporate culture will create an engaging work environment, ultimately making it easier to execute.

These benefits help to maintain reasonable costs and safe, reliable products and services for our customers, as well as economic development, philanthropy, volunteerism, and advocacy in our communities. We understand uncertainty creates a discount. In 2013 is the year for us to reduce some of that uncertainty.

One last item before I turn the call over to Drew. Typically, we would not mention to you the retirement of our human resources leader. However, in the current case it's different.

In September, a long-term Entergy employee, and even longer term friend of mine, Renae Conley will retire. For the last couple of years, Renae has been our HR leader and prior to that, she led our largest jurisdiction for a decade through some of the most difficult times the Company has faced, for example, in 2005 during Katrina and Rita.

Many of you however will recall that Renae was the driving force behind turning Entergy's Investor Relations group into the high quality organization it is today. And if you've been in the business as long as I have, you probably remember her filling Investor Relations roles at Cinergy and before that, PSI. For those of you that know her, you realize how capable she is, you know her tenacity, her strength, her intelligence, and her kindness.

I know many of you listening that are investors will recall her many contributions, and I hope you will feel free to contact her during the next month to wish her well. And I know many of you who are employees feel the same sadness as I that she is leaving us, but also tremendous happiness for her as she enters the next phase of her life. All I can say is, she will be greatly missed.

Now, I'll turn it over to Drew.

Thank you, Leo. Good morning, everyone. In my remarks today, I will cover quarterly financial results and expectations for 2013 and beyond. This will include a discussion on human capital management.

Now let's turn to the quarterly financial results. Slide 5 summarizes second quarter 2013 results, on an as-reported and operational basis. Operational earnings per share were $1.01, versus $2.11 a year ago. Second quarter as-reported earnings in both periods included special items for expenses associated with human capital management in 2013 and the spin-merge of the transmission business with ITC in 2012 and 2013.

Turning to operational results, slide 6 summarizes the mayor drivers by business. Utility operational earnings per share were lower in second quarter of 2013 due largely to a tax benefit and associated regulatory credit in the comparable 2012 period. Together, these two items provided a net benefit of approximately $0.44 in the second quarter of last year. Excluding these items, the quarter-over-quarter operational results declined approximately $0.15. The overall decrease is attributable to the net effects of higher non-fuel O&M and higher depreciation expense, partially offset by higher net revenue.

A portion of the increased non-fuel O&M and depreciation expenses, as well as the increased net revenue, reflect investments placed in service in 2012. Previously identified higher benefit costs primarily from pension discount rates also contributed to the quarterly O&M variance. Second quarter 2013 net income also included approximately $7 million incremental pre-tax expense as a result of the ANO Industrial Act. This amount reflected incremental non-fuel O&M less investment recorded for insurance proceeds and reduced refueling outage amortization expense.

While on the topic of ANO, I would like to give a quick update. First, recovery efforts for ANO have progressed well. Unit one could return to service as early as August, pending recovery continues to go well.

Second, we've updated cost estimates for the assessment and restoration, re-removal, and replacement of the used property and equipment in the range of $95 million to $120 million. This estimate does not include replacement energy. That may change as we continue restoration activities.

Finally, Entergy Arkansas recently filed a lawsuit in Arkansas state court seeking recovered damages related to the ANO event and is continuing to assess other options for recovering damages, including insurance and other legal actions.

Now, turning back to the results for the quarter at the Utility. Utility net revenue increased due to the prior period regulatory credit noted earlier and pricing factors. As with first quarter of 2013, pricing adjustments included regulatory action for major generation investment sites and service in 2012. These investments benefit customers through improved operational efficiency and favorable environmental profiles.

Utility retail sales volume on both an as-reported and weather-adjusted basis declined quarter-over-quarter. Leo reviewed certain sales drivers in his earlier remarks.

In setting 2013 guidance, we anticipated declines in residential and commercial sales from energy efficiencies and growth in industrial sales from expansion. However, year-to-date results are below expectations for all segments, especially in the industrial segment. We expect better industrial performance over the balance of the year, particularly in the fourth quarter as the large expansion is scheduled to start up. Longer term, we see support for 1% to 1.25% sales growth.

At EWC, operational earnings were $0.33 per share lower than the second quarter last year. This period-over-period decline was due to largely to the lower operational EBITDA drivers which I will review shortly. EWC results also reflected higher de-commissioning expense due to an item recorded in the second quarter of last year, partially offset by lower income tax expense. Slide 7 summarizes EWC's operational adjusted EBITDA for second quarter 2013 and 2012.

The $66 million decrease was due primarily to lower net revenue, driven by decreased output from EWC's nuclear fleet. The nuclear fleet had 26 additional outage days from both refueling and maintenance outages. While second quarter day ahead Northeast energy prices were roughly 35% higher than prior-year level. We saw a large decline in prices over the course of the quarter, due in part to reversion of New England natural gas prices from high winter levels, as well as weak supply and demand conditions in the broader natural gas market.

Including the impact of hedges, average energy price for the current quarter in EWC's nuclear portfolio declined approximately $3 per megawatt-hour versus second quarter last year. Leo has already reviewed the underlying drivers for the capacity markets. I will note that we continue to expect to see these constructive fundamentals going forward in New York with the new Lower Hudson Valley zone, though regulatory intervention remains amiss.

Slide 8 summarizes the cash flow performance for the second quarter. Operating cash flow is $572 million, $15 million lower than the same period a year ago. There were several drivers, both positive and negative.

While the overall decrease was $15 million, the variance by segment was significant higher. This is in large part due to inter-company tax payments. Because Entergy filed a consolidated return, income tax obligations are routinely settled between our legal entities and issues are resolved.

In the current quarter, the inter-company activity was largely due to the tax settlements which we recorded in the fourth quarter last year, related to the tax treatment of the Utilities de-commisioning liabilities. Ultimately, timing of payment to the IRS will consider many factors, including storm loss, carry backs, utilization of NOLs, and the taxable income of other entities in the consolidated tax group. Slide 9 summarizes the 2013 operational earnings guidance from $4.60 to $5.40 per share. I know you are familiar with the drivers so I will not repeat them today. Operational guidance does not reflect the two special items I discussed earlier.

Now, I'd like to turn to a discussion of drivers for 2014 and beyond as they are shaping up today. Starting with HCM on slide 10, human capital management is designed to create sustainable value for four key stakeholders. And will have real lasting impact on Entergy by changing the way we work while reducing ongoing spending and maintaining or improving safety and reliability.

We expect total annualized savings to be in the range of $200 million to $250 million by 2016. While execution of the initiatives and realization of the savings will occur over the next two years, the bulk of the savings will be realized in 2014. Savings realized at the Utility operating companies will be recognized appropriately in our regulatory filings when those savings and the costs to achieve are known and measured. This process will vary by jurisdiction.

Estimated savings are primarily from the organizational redesign effort which will be largely completed by the end of this year. The savings estimate also includes cost reductions from the other areas Leo discussed. On a preliminary basis, the total $200 million to $250 million savings goal is expected to be split approximately 80% to 90% non-fuel O&M in the balance and capital spending. And approximately 60% to 65% at the Utility and the balance largely at EWC.

In order to implement our HCM initiatives, we expect to incur one-time costs to achieve in the range of $145 million to $185 million. The majority of these costs will be incurred in 2013 and will be classified as a special item. The level and timing of HCM savings are important in considering future O&M levels.

Our future spending and earning trends will be affected by other factors as well. Slide 11 summarizes our non-fuel O&M and refueling outage expenses over the past few years.

The 2013 baseline of approximately $3.5 billion represents expectation excluding past and future costs associated with HCM optimization and the ITC transaction. Considering all these factors, we expect a three-year compound annual growth rate off 2013 base of around 1.5% to 2.5% including HCM savings. Growth rates can vary from year-to-year.

In addition to the level of HCM savings, other factors to consider for future O&M levels include the effects on proposed ITC transactions, variations in pension discount rates, spending on initiatives such as energy efficiency, inflationary pressures, and incremental regulatory compliance costs. Some of the factors driving changes in O&M expense, such as MISO costs, energy efficiency costs, and storm reserve have corresponding offsets in net revenue.

Looking ahead to 2014, slide 12 summarizes preliminary major drivers to consider based on where we stand today. For the Utility, whether or not the spend spin-merge is completed is a key factor in 2014. Excluding that transaction, we are affirming our five-year compound annual growth rate for Utility net income to around 6% for 2014.

In addition to HCM, many initiatives under way now will determine our ability to deliver on this expansion outlook. Those include the outcomes of pending rate proceedings in Arkansas, Mississippi, and Louisiana and to a lesser degree, the to-be-filed rate cases in Texas. A level of sales growth is a factor to watch.

As I noted earlier, 2013 sales to date are lower than expected. However, we believe that over the longer term annual retail sales growth of 1% to 1.25% is achievable, even after factoring in energy efficiency and HCM optimization efforts. As Leo explained, our service territory has strong economic development activities signaling the potential for long-term growth.

Recent contracts combined with other major projects that our economic development teams are working on could have a significant impact. Even with higher growth and a lower-priced industrial segments, there is still incremental revenue and customer benefits from spreading costs across higher volumes.

For EWC, energy and capacity markets are a major factor for the financial performance in activities. The 2014 average revenue per megawatt-hour for EWC's nuclear fleet is expected to decline approximately $3 per megawatt hour based on the June 30 forward markets. A 23% open energy position combined with market variability and certain hedge positions leads to a range of possible price outcomes as you can see in the price sensitivities outlined in table 7. Variations in nuclear plant outages both planned and unplanned can affect EWC's earnings.

We now expect to have full refueling outages next year as a result of moving the Palisades refueling outage from fall of this year to early 2014. Our ability to identify and execute on opportunities to improve EWC results is important for that business. This includes the O&M factors that I discussed earlier. Income tax expense is an item that varies year-to-year and segment, and we always have a potential for portfolio management activities.

Through all of this, we are focused on managing the strategic imperatives and positioning ourselves to take advantage of the opportunities and face challenges that come our way, while maintaining a firm commitment to deliver sustainable value to all our stakeholders.

Now, the Entergy team is available for your questions.

Thank you.

(Operator Instructions)

We'll go first to Angie Storozynski with Macquarie.

I wanted to start with slide 22, the illustrative adjusted EBITDA for EWC, and how it ties into slide 12. You're showing a step down in EBITDA for the merchant business in 2014 even though we have quite a considerable O&M cut and a likely pick-up in capacity revenues in New York. I know that there's a reduction in energy prices but I'd still expect a bit of a stronger projected EBITDA for that business.

Well, the reality is that we're still facing lower prices overall. As Drew suggested, on a per megawatt-hour basis we're seeing a reduction.

While we're encouraged and we've seen uplift from the Lower Hudson Valley capacity zone. The fact is, in a lot of the other markets, specifically the New England market we're not getting appropriate rents in terms of capacity prices. So, net-net, you're correct, we are looking at a decline in total EBITDA for EWC for 2014.

That bar already fully incorporates cost cutting and MISO's projections for the capacity price uplift?

I don't believe that it includes all of the HCM efforts, but it does reflect our point of view on current market conditions.

Okay. Then, on slide 12, could you just explain a little bit, what is this potential for portfolio management activities? What do you mean by those?

As we look at that portfolio, as Leo mentioned, we consider all options. We do this on a regular basis. Obviously, we look at a hold and optimize scenario, where we're taking the steps to reduce our costs and be as efficient as we can at each and every facility.

We also explore market opportunities to determine if any asset or portfolio assets would be better owned by another party. And we also continually evaluate the potential for a shut-down of a facility. When we talk about options, those are the three different areas that we constantly look at. That's similar to what we've always have done.

Why is it mentioned on corporate and not under EWC?

This is Leo. That's primarily given, who leads some of those efforts and they work in conjunction with the folks within the business units. The people that do that activity primarily are driven out of the corporate organization. That's more our organizational structure than anything else.

Last one. We have those projections of O&M cuts, targeted projections by 2016. Can you explain to me the timing of this announcement, vis-a-vis your pending rate cases and ITC transaction?

Should it facilitate the ITC deal and your pending rate cases? How will it actually be incorporated in the pending regulatory filings?

I'll let Rod take that. Rod West, who's our Chief Administrative Officer, all of the HCM effort is being directed under his organization. So I'll let Rod take that.

To be direct in answering your question, the timing is not designed to facilitate or feed a regulatory point of view. The timing of the HCM announcement really does reflect where the Company's planning process has involved, to where we think we have a clear point of view on the savings. And our confidence around being able to articulate what we think the bottom line impact would be.

As we begin this process, Leo, I recall announced at EDI last year as we were formally beginning, to publicly, at least, execute on our point of view around MISO and ITC. We had perspectives around where the organization needed to be on a going-forward basis. As we evolved, as the analysts evolved, we felt more and more comfortable about when wed be able to communicate. The timing, it just reflects where we are.

Okay. Thank you.

Thank you, Angie.

Once again we ask that you limit yourself to one question and one follow-up. We'll go to Dan Eggers with Credit Suisse.

Good morning, guys. Following up on the cost cutting program and the numbers out there, the overall savings are up significant relative to --. On the magnitude of cost savings, could you share a little more color on where you expect to find the savings?

We've seen past M&A transactions recently. Their savings have been in line or smaller than what you are talking about today. Trying to bucket those better would be helpful, I think.

Sure, Rod?

Dan, as we discussed in prior conversations, what you know and what we call the HCM process is centered around four work streams. Both Drew and Leo alluded to them.

The first is the Oregon process. I think that one answers your question, in terms of where we think the lion's share of what we've communicated today rests, particularly as we look to what meaningful in 2013 going into 2014. Then you have comp benefits, procurement costs, management, and then the non-employee-related operational expenses. The lion's share of the savings, order of magnitude, half to two-thirds perhaps comes from our Oregon in process point of view.

You guys reiterated the 6% earnings growth in Utilities. That would then include the 2014, I guess? Was there a bit of a backfill on supporting that 6% growth? Or is that number actually biased higher because you'll have more savings in those numbers for next year?

We are not considering it added to the 6%, as I mentioned. There could be some small benefit short term, but ultimately, we expect it to be recognized in filings when it's known and measurable within the regulatory process of Utilities. We're not counting it as incremental to the 6% target.

Okay. Thank you.

(Operator Instructions)

We'll go to Jonathan Arnold, Deutsche Bank.

On the ITC mitigation plan as proposed, how would you envisage those credits flowing through the financial statements, or not?

We're still looking at it. Preliminarily we would expect it would be reflected in the net revenue. It could change with final orders that we ultimately get.

The only change that we would see is whether or not we would recognize a liability on the balance sheet for the first five years. After that, everything is contingent, so it clearly wouldn't be a balance sheet liability. But at this point we expect it to flow through in net revenue.

Flow through in net revenue, as incurred basically?

Correct.

And my second one, on page 12, under EWC, you mentioned depreciation as a driver for 2014 and then declining useful life of nuclear assets. Can you clarify the latter part of that statement?

That was related to potential change where currently we have accelerating depreciation, as we get closer and closer to the end of life of the units. We may make a change where we flatten that out a bit. But I think that is the primarily thing we are talking about there.

So that would be beneficial to earnings?

Well, it would be beneficial to the end tail of the earnings. It would be against earnings. It would be harmful to earnings.

The negative 2014 driver?

Yes.

Is that included in the sort of EBITDA look that you put on that later slide?

No, it's not.

Okay. Any idea how much that might be or is it small?

We don't have that information right now but we'll give you a additional details later.

Next to Andy Levi at Avon Capital.

How are you guys doing?

Great.

I'll go quick so you can get someone else in there. Getting back to the cost savings, on the EWC side, you had 35% to 40% of that segment would realize the cost savings. Then, as you said, you have the EBITDA on that slide coming down in 2014.

And then you were vague on whether ultimately the savings were going to be incorporated in 2014. Does that mean that we'll see them in 2015? I need clarification and then I have one other quick follow-up.

I think, Andy, the clarification was that the EBITDA number did not include HCM, but we would anticipate there would be some.

In 2014. The bulk of it you can expect to see for EWC in 2014.

Okay, but that slide does not include the savings from HCM.

Correct.

Perfect. Then other thing, moving on to ITC very quickly, you have all these rate mitigation things for the various states. Can you give us a breakdown on how much of those savings are from the system agreement versus other savings?

Can you repeat that question, Andy?

On the ITC Entergy deal, there are savings from the system agreements going away, right? And then there is savings. So, I'm wondering what the breakdown of that is.

I'm throwing out a number. In Louisiana, $100 million of rate mitigation that's going to the customer. What is the breakdown of that?

Andy, this is Theo. Are you referring to the avoided costs?

Yes, exactly.

The cost column on page 3, slide 3?

I don't know if it's on page 3.

If you are referring to the avoided cost column, it includes costs that would go away as a result of the transmission business going away. Therefore, there is no more MMS2 transactions potentially between the various operating companies. Also, I think it reflects maybe a change in zonal -- that pricing zone's structures. I don't have it in front of me, the various pieces and parts, as it relates to those two components, but I think we could follow-up and get that to you.

Thank you very much. I'll let someone else go.

We'll go next to Greg Gordon at ISI Group.

Thanks, guys. When I think about the HCM program in terms of its impact on your Utility businesses, should I think about this as being -- driving the ability for you guys to have a higher confidence level in earning, at your authorized returns, across the jurisdictions prospectively? I think the guidance this year, for instance, presumes a significant level of under-earnings.

So, the HCM program would have two benefits. One, it would reduce the necessity for rate increases but also keep your costs profile from creating regulatory lag? Is that the right way to think about it?

That's fair, Greg. The major component is to become more efficient. And through that efficiency, we should end up with lower rates, lower costs, to the customers, and have a better shot at earning the rate of return that we're allowed. That's correct.

Right. One follow-up, if you were to be ordered to implement the rate mitigation plans by establishing regulatory liabilities, as opposed to running it through the P&L. We should assume then that's an offset to rate base, right? That lowers the rate base. Is that right?

Drew?

Well, we would only get to do that if we got a rate order or rate deferral. I would think of it more as a regulatory asset that we would be able to realize over time, on the one-time incurred costs.

If you had a regulatory liability, that would flow through as a contra-expense, but reduction in revenue. So, you'd wind up having an upfront write-down, and then there would be a cash impact as you flowed the credits back, but not an earnings impact, right?

This is Theo. I think what would happen, if in fact you booked it up upfront, you would recognize the liability. But the cost obviously would be recognized as an expense at the time you booked the liability.

If in fact that was the case, as Drew said, that's not what we're saying at this point in time. What would be the case, if in fact, you had a liability as part of a regulatory construct, I would imagine that you're not likely to see that as it relates to regulatory rate setting going forward.

Okay. So, you think the most likely outcome, should be mitigation plans be approved, is they'll flow through as they flow back to customers, you'll incur the expense. Your cost cutting plans allow to you to plow through that and still close the gap between the current ROEs and your future authorized ROEs?

If in fact, it happens as we see it or expect it today, you would see the impacts of the rate mitigation flowing through currently as reduction of revenue, which obviously would put downward pressure on ROE. You would also have, as the regulatory processes move forward, you would see the impact of cost cutting making their way through the regulatory process. That could happen at various points in time.

Obviously as that happens, Leo mentioned earlier, we would see rates being adjusted to reflect those changes in cost structure within the Utility. So, for a period of time, there is a potential that you could have offsets. But again, as you go forward and the regulatory process encompasses those rate reductions within the setting of rates, the rates would be adjusted to commensurate with that. Those benefits would flow back to customers at that point in time.

Great, very clear. Thank you.

We'll go to Steve Fleishman at Wolfe Research.

Two questions in 10 parts. Yes. Just on the percent O&M increase could you possibly break out the 0.5% to 2.5% just for the EWC business?

I don't have that in front of me, Steve.

Also on the target of 6% growth in 2014. If you achieve that in 2014, would you generally be earning your allowed returns in your regulatory jurisdictions overall? Or would you still be under-earning?

This is Theo. I believe if we achieve that, I think the answer is yes, we'd pretty much be earning our allowed ROEs within the construct of the jurisdictions.

Okay. In theory, the cost cutting is helping you to get to earn it and will in the future at the Utilities, I guess. One last thing on the HCM, the compensation benefits procurement that you mentioned, are those included in the $200 million to $250 million or not?

Steve, this is Rod. They are currently included. I was making the point earlier that the lion's share of that number was in the Oregon process but all four work streams are and will continue to contribute to the point of view on the $200 million to $250 million.

Thank you very much.

We will go next to Charles Fishman at Morningstar.

Hi, on the rate mitigation plan in year six when it's determined by the savings, who is the arbitrator of that savings? Is it MISO? Is it the state commissions? Do you hire an independent consultant? In other words, who's making that decision of what the savings are?

Charles, if you look at what has been filed as a part of that rate mitigation plan, what has been proposed is an independent third party that would be mutually agreed upon by ITC and a regulatory body.

Okay. Thank you. That's it.

Thank you.

Unfortunately, that is all the time that we have for questions today. I'd like to turn the conference back over to Ms. Waters for additional or closing remarks.

Thank you, Anthony. Thanks to all for participating this morning.

Before we close, we remind to you refer to our release and website for Safe Harbor and Regulation G compliance statements. Our call was record and can be accessed on our web site or by dialing 719-457-0820, replay code 453 2989. The recording will be available as soon as practical after the transcript is filed with the US Securities and Exchange Commission, due to filing requirements associated with the proposed spin-merge transaction with ITC. The telephone replay will be available through August 7.

This concludes our call. Thank you.

This does conclude today's presentation. We thank everyone for their participation.